UNITED STATES OF AMERICA 

COMMODITIES FUTURES TRADING COMMISSION

PUBLIC ROUNDTABLE TO DISCUSS 

DODD-FRANK END-USER ISSUES 

Washington, D.C.

Thursday, April 3, 2014 
PARTICIPANTS: 

MARK WETJEN, Chairman

SCOTT O'MALIA, Commissioner 

PANEL ONE: REGULATION 1.35 DISCUSSION

Moderators:

KATIE DRISCOLL 

DUANE ANDRESEN 

DAVID STEINBERG

Panelists: 

SCOTT CORDES 

CHS Hedging, Inc. 

JERRY JESKE 

Mercuria Energy Trading, Inc. 

TODD KEMP 

The National Grain and Feed Association 

LANCE KOTSCHWAR 

Gavilon 

ERIC PERRY 

Scoular Company 

ROBERT POWELL 

Etrali Trading Solutions 

JOHN RUSSO 

Global Relay 

ROBBY SEN 

Ameriprise Financial 

ERIC SMALLEY 

Growmark 
PARTICIPANTS (CONT'D):

STEPHEN WALDMAN 

Tudor Investment

PANEL TWO: EMBEDDED VOLUMETRIC OPTIONALITY DISCUSSION

Moderators:

CARLENE KIM 

DAVID ARON 

JOHN PAUL ROTHENBERG 

Panelists: 

JAMES ALLISON 

ConocoPhillips 

SUSAN BERGLES 

Northwest Natural and American Gas 

Association 

CHUCK CERRIA 

Hess Corporation 

PATTY DONDANVILLE 

Reed Smith 

PAUL HUGHES 

Southern Company 

JERRY JESKE 

Mercuria Energy Trading, Inc. 

RYAN JOSEPHSON 

Bonneville Power Administration 

TODD KEMP 

The National Grain and Feed Association 
PARTICIPANTS (CONT'D): 

TOM NUELLE BP DAVID PERLMAN 

The Coalition of Physical Energy 

 Companies 

ERIC PERRY 

Scoular Company 

WALLY TURBEVILLE 

Demos

PANEL THREE: "SPECIAL ENTITY" DE MINIMIS THRESHOLD FOR SWAP 

DEALING TO GOVERNMENT OWNED ELECTRIC UTILITIES

Moderators:

ERIK REMMLER 

Panelists:

PATTY DONDNAVILLE 

Reed Smith 

RANDY HOWARD 

Los Angeles Department of Water and Power 

JERRY JESKE 

Mercuria Energy Trading, Inc. 

TERRY NAULTY 

Owensboro Municipal Utilities 

WILLIAM RUST 

The Energy Authority 

VIRGINIA SCHAEFFER 

Bonneville Power Administration

JIM TRACY 

Sacramento Municipal Utility District 

* * * * * 
P R O C E E D I N G S

(9:33 a.m.)

MS. DRISCOLL: Good morning everyone. 

We're going to get started. Welcome to the 

CFTC's End-User Roundtable and thank you all for 

joining us today, particularly to our roundtable 

participants; thank you for agreeing to come and 

discuss these important issues with us.

I'm here today to lead the roundtable 

on Regulation 1.35, but we're also going to have 

a roundtable on volumetric optionality and the 

special entity De minimis for swap dealing. Our 

Chairman, Mark Wetjen wanted to say a few words 

before we start.

MR. WETJEN: Thanks, Katie. Thanks 

everyone for being here. We have a good agenda 

and it looks like a good list of participants and 

witnesses to help us talk through some of these 

issues and so we really appreciate everyone being 

here and your contributions to the process of 

continuing to work through some of these 

lingering end-user issues that have developed 

from some of our rule makings over the last 

several years. So thanks again for that.
I wanted to just make one other 

announcement, which is that this morning I put 

into circulation a rulemaking that will follow up 

on the no action letter we released a couple of 

weeks ago on the special entity de minimis 

threshold and it, in substance, it's by and large 

the same as the no action letter but we thought 

it was appropriate to follow up that action with 

an actual rule proposal.

So that is in circulation as of this 

morning and hopefully we can get that out for 

public comment relatively soon. And so, 

obviously, there will be a session later on that 

particular issue and so we're eager to hear what 

the participants have to say and, of course, 

anything said here should be, or could be anyway, 

followed up with a public comment letter filed in 

response to the proposal.

So I wanted to make that announcement 

and let everyone know that that's coming 

hopefully very, very soon and in the mean time, 

we look forward to today's roundtable and talking 

through both the special entity de minimis 

matter, but also 1.35 and volumetric optionality. 
So thanks very much. Scott, did you want to say 

anything?

MR. O'MALIA: Sure. I appreciate you 

putting that into circulation. And you had some 

important -- take these roundtables and make 

something of them because if it's worth fixing, 

it's worth fixing right. And I think we're 

making some headway on special entity definition 

to make that a rule instead of a lingering no 

action.

I'm pleased that we're having 

circulation or out for comment changes to the data 

rules as well. So some of the other weighty 

issues that we're going to tackle here include 

1.35, which I know we've heard from a lot of 

end-users the impact of that, volumetric options; 

I'd like to see further action to make our hedging 

definitions consistent and fair and consistent 

with current action.

I think that's something we ought to 

address going forward in the future and I know 

we've got a variety of rules that have a slightly 

different take on what's allowed for hedging but 

I'd like to have it a little more conforming and 
consistent. So I look forward to today's 

meeting. Thank you to the Chairman for -- for, 

you know, initiating these meetings and I look 

forward to actual action once these things are 

finished; thanks.

MR. WETJEN: Just one other thing, 

Commissioner O'Malia reminded me of it when he 

made his remarks. We haven't made an official 

announcement yet, but we've begun discussions 

this week, after some good meetings earlier in the 

week with my friend Todd Kemp who's here today, 

but we're going to have, at some point in the near 

future, another session either through an 

Advisory Committee meeting or roundtable, but 

we'll have a session on anticipatory hedging, 

which is something that there's been a lot of 

interest in on the part of the end-user community.

So once the details, when and how to put 

that together, are sorted out, we will make an 

announcement concerning that. But I imagine 

that'll be sometime in the next week or two, and 

make the announcement, and hopefully have the 

meeting and the session itself soon thereafter. 

So be on the lookout for that as well.
MS. DRISCALL: So before we get to the 

substance, I just have a couple of instructions 

from our Technology Department about how the 

microphones and recording system work.

So please be aware that the microphones 

are push to talk. Please keep the microphone a 

few inches away when speaking, press the white 

button on the base before you speak. When your 

indicator light appears red, your microphone is 

on. When you finish talking please press the 

microphone again to turn it off.

A limited number of microphones can be 

active at one time. Please turn your microphone 

off after speaking to allow others to speak 

without issues. Please refrain from putting any 

mobile cell device on the table as they may cause 

audio interference. For the teleconference 

participants, it is listen only and for recording 

purposes, please be advised that this meeting is 

being recorded.

So this panel is here to discuss 

Regulation 1.35, which is one of the Commission's 

record keeping rules. It applies to Future's 

Commission's Merchants, introducing brokers, 
RFEDs, and members of a DCM or SEF. It actually 

pre-exists Dodd-Frank. It's been in the books 

for a long time now. But in December 2012, the 

Commission amended Rule 1.35 to conform existing 

record keeping requirements with new record 

keeping requirements under Dodd-Frank that apply 

to swap dealers and major swap participants.

Some of the big areas of change were to 

put in the rule that written communications 

include any communications that lead to the 

execution of a transaction in a commodity 

interest or a related cash or forward and that 

such communications include electronic 

communications like emails, instant messages, 

and text messages.

That part of the rule applies to FCMs, 

IBs, and RFEDs, and all members of a DCM and per 

the amendments, also members of SEFs, swap 

execution facilities. The other major change to 

the rule was promulgating an oral record keeping 

requirement. And that's basically telephone and 

video recording.

That part of the rule applies to FCMs, 

large introducing brokers, RFEDs, and certain 
members of DCMs and SEFs, who are also required 

to register with the Commission, with certain 

carve outs within that group.

Also, where the written records 

requirement applies to commodity interest and 

related cash or forward transactions, the oral 

record keeping rule only applies to commodity 

interest transactions. And a commodity interest 

is defined as a futures contract, an options 

contract, for ex transactions, and swaps. So 

we've heard a lot from market participants about 

challenges with complying with these new rule 

amendments and we do appreciate, even during the 

rulemaking process.

We had a lot of discussions and we've 

also had a lot of discussions since the rule was 

finalized and so we're here today to discuss some 

concerns from the end-user part of the markets. 

We have a couple of representatives from the 

Commodity Trading Advisor and Commodity Pool 

Operating Community, and then we also have some 

representatives from third party technology 

vendors who are actually providing some of the 

record keeping solutions that are available 
today.

So I would just ask -- I'm just going 

to pose some questions to the group and if you do 

volunteer to respond, if you could just introduce 

yourselves, the entities you represent, and what 

status those entities have in the market, if 

you're registered, what your registration status 

is.

So the first topic that I wanted to 

discuss was the term related cash or forward. 

That applies to record keeping obligations for 

written communications.

Under Rule 1.35, a related cash or 

forward is a purchase or sale for immediate or 

deferred physical shipment or delivery of an 

asset related to a commodity interest 

transaction, where the commodity interest 

transaction and the related cash or forward 

transaction are used to hedge mitigate the risk 

of, or offset, one another. Can someone here 

speak to how that definition relates to your 

business and how it might provide some challenges 

with keeping records of your written 

communications?
MR. PERRY: Katie, thank you for the 

opportunity to the Commission to come and work 

through these issues today. My name is Eric 

Perry. I'm with the Scoular Company in Overland 

Park, Kansas and we are cash commodity merchants. 

Our business is buying, selling, moving, managing 

the supply chain on cash agricultural 

commodities.

So the way that 1.35 is written and the 

related cash or forward, captures every 

conversation that we have; leads to the 

execution, captures every conversation we have. 

In this space, we do not do customer business. 

Our entire derivatives book is to manage our own 

internal risk and everything that we do is buying, 

selling, and moving that cash commodity.

So our merchandisers, every 

conversation they have every day, unless they 

happen to be talking about, you know, to a buddy 

about fishing, has to do with cash commodities, 

purchase sale, or movement thereof.

So the dialogue that takes place from 

the time they hit their desk until the time they 

leave, is captured in 1.35. So it significantly 
impacts the business that we do.

MS. DRISCOLL: Is there anyone else who 

wanted to comment on the definition of related 

cash or forward?

MR. KOTSCHWAR: Katie, this is Lance 

Kotschwar with Gavilon and I'm here on behalf of 

the Commodity Markets Council today. Just to 

follow up on what Eric said, thanks for having us 

here. We think these are important issues. It 

covers the whole gamut of what we're doing but I 

guess the -- the real challenge we have is when 

you -- when you look at related -- a related cash 

transaction and you combine that with the notion 

that these records needs to be index searchable.

I'll use an example. We're normally, 

around harvest time, we're long physical so we're 

short on the exchange and the days and months 

after that we are merchandising our grain. So in 

any given day we will be buying and selling it at 

many, many locations.

So if we're taking -- I don't know what 

our average volumes were for this -- this week but 

let's just assume that yesterday we -- we netted 

out being -- we sold out physical of, I don't know, 
500,000 bushels. So what are we going to do? 

We're probably going to go, you know, reduce our 

position on the exchange. But that net effect is 

made up of hundreds, literally hundreds, of 

physical transactions.

So for us to be able to -- we can capture 

all of the -- the -- the conversations and 

communications, but trying to tie them back to 

what we do on the exchange would be, I don't know, 

looking for a needle in a haystack. We can do it 

on the aggregate, but I don't know what that gets 

you. You know, we have -- we have all of our 

contracts for our physical transactions. That's 

what we find in our business needs to -- and that's 

all we need to keep.

We don't -- we don't find it necessary 

from a business perspective to keep all of the 

chit chat, instant messaging -- well, instant 

messaging we are keeping actually. But we 

normally would not be keeping that because 

it's -- we don't -- we don't need that to prove 

our physical business.

So it would -- we're -- we're scratching 

our heads wondering if we really are complying 
when it comes to making these things indexable and 

searchable. We've got them. But to tie them 

back to any particular transaction, we'd have to 

talk about that and figure out what that exactly 

means because it's not a transaction, it's 

hundreds of transactions.

MS. DRISCOLL: So Lance, just to be 

clear, you're referring to the requirement that 

records be searchable and identifiable by 

transaction and counterparty?

MR. KOTSCHWAR: Yes.

MS. DRISCOLL: Is that right? Thank 

you. So we've actually heard this issue quite a 

bit about concerns and challenges with complying 

with that part of the rule and I -- I thought 

perhaps Mr. Russo could speak a little bit to that 

as a technology vendor.

MR. RUSSO: Hi, and thank you for 

having me. I work for Global Relay and we are a 

cloud based archiving vendor and we deal with 

these kinds of issues every day. We've got, I'm 

going to say nearing 100 --

SPEAKER: John, could you pull that a 

little closer?
MR. RUSSO: Sure, sorry about that. 

We've got it close to 100 CFTC registered 

organizations that use our services today. And 

what I wanted to add, along the lines of what Lance 

had mentioned, was that although we can archive, 

and index, and serialize, and store this data in 

worm related storage facilities, the challenge 

that would come up for most organizations is how 

do you track down by transaction id.

So we can index the data, and we were 

having some conversations earlier, where you can 

search by the actual transaction id number and 

retrieve anything that's relevant to those 

numbers or the custodians that might have been 

dealing with that transaction. But it becomes 

complex in that the organizations would have to 

follow a strict template based policy within the 

organization to make sure they included those 

terms in all of their communication so that way 

it can be tracked.

So with respect to email or instant 

messaging, email might be easier if you've got a 

disclaimer and you're adding some sort of 

transaction identifier to the bottom of an email, 
and that could be company policy. It may not be 

ideal, but when you get into the space of instant 

messaging and SMS, that's where you're going to 

come into some issues. And I think the challenge 

is that a lot of these member firms are going to 

have is trying to tie back specifically to the 

transaction id.

So although you can go back and say well 

I know these 15 custodians might have been 

involved in that deal, I can't necessarily 

pinpoint that transaction id within the 

communications and it becomes a bit onerous to 

then try to gather this large amount of data and 

then call it down.

So the technology is there to -- to 

grab, and capture, and retrieve all of that 

information. I think the challenge is more and 

lie in calling down that data and producing what's 

required.

MR. JESKE: Is there -- is there any way 

to automate the assignment of a transaction id?

MR. RUSSO: To some extent. Again, 

there are electronically based policies that you 

can implement in the technologies available 
today, whereas if you're hitting on certain key 

words or phrases or if you're using internally 

published documentation as a template that you're 

distributing to your clients or you're using for 

communications, you can then apply these policies 

on the fly so that when -- when the communications 

are being archived, they're being scanned and 

indexed and then anything that triggers those key 

words or phrases or meets the rules of the 

criteria that identify them as a transaction that 

then you could pick up and capture that 

information to sort of do it automatically.

But my understanding of the transaction 

id is something that is a bit more difficult to 

capture versus, let's say, some sort of sales or 

marketing materials, you know, along those lines. 

There's not necessarily a consistent format to 

look for and that would be the challenge.

MR. JESKE: Katie, my name is Jerry 

Jeske and to add to what some of the other folks 

are saying -- I'm Chief Compliance Council from 

Mercuria Energy Trading. We -- we have offices 

and facilities in over five different continents, 

you know, several different countries, different 
languages, dialects, and so forth within our 

organization, not to mention with people we deal 

with internationally.

We're an energy end-user. We buy, 

purchase physical commodities in the chain of 

commerce. We're not members though. We're not 

members of an organization. I think Mr. Russo 

mentioned that in connection with some of the 

other gentlemen that just spoke, I think the key 

concept here is membership.

If you go back and look into the Reg 1.35 

and its iterations over time, back from December 

'48, 1963, 1971, and as recent as 2009, that 

concept has been universal throughout each one of 

the changes in 1.35. Membership meant something 

back then. Membership doesn't mean as much 

today.

Membership is something that was 

referenced in every one of these regulations that 

changed over time as somebody who stood in the 

pit, somebody who dealt with customer orders, 

somebody who had an obligation to keep an audit 

trail related to those orders.

What this new change has ensued is an 
expansion, a vast expansion, past the individual 

who's a fiduciary responsible for the execution 

of that order and has gone into customer activity. 

Customers here are not addressed in the statute, 

I certainly don't believe that was congressional 

intent whatsoever, but somehow it's worked its 

way into this regulation. That now customer 

communications are supposed to be logged and 

monitored.

Let's not forget something; U.S. 

sentencing guidelines for corporations require 

not just maintaining and archiving, but 

surveillance. These things cost a lot of money. 

So do you want to be a member of a DCM or a SEF? 

I think that's a big dollar question as it relates 

to 1.35.

Some of the technology may be out there, 

but when is a trade a trade? When is there a 

meeting of minds over the phone or on an in chain? 

You can't get that deal id number until there's 

an actual deal I would assume, Mr. Russo.

MR. RUSSO: That's correct, yes. 

Yeah, I mean just to expand a little bit upon the 

supervision aspect of it because we've been in 
that space for quite some time, not just while 

I've been with Global Relay but in the past I've 

worked with organizations to deploy supervision 

platforms. What I can say is that technologies 

have come a long way and that it's become much more 

affordable today than it has been in the past. 

And I agree with you that in the past you had to 

deploy significant infrastructure and house to 

manage that kind of supervision, unless you were 

manually going to print out emails and read them.

But today with the technologies that 

are available, it's quite affordable and 

approachable to even the smallest organization 

to -- to employ those technologies. With that 

being said, like I said, the main challenge that 

I see from a technology perspective is 

identifying the transaction ids.

And I think that language, as it stands 

in the documentation that was forwarded to me, 

would be the more challenging bit for us to meet 

for our own clients.

So if we go in and they say ok, how do 

I do this by transaction id, I can 

simply -- everything is indexed and I can search 
for those transaction id numbers and I would 

assume that I would get some of it. But I -- I 

think it would have to be worked hand in hand with 

the policies that are written up in house, within 

the organizations, on how do they address their 

transactions.

So it would be a combination of the 

actual employees that were performing 

those -- those transactions. You would search 

for their data during the timeframe that the 

transaction may have occurred, maybe a few days 

prior, a few days after, or even longer depending 

on how long it takes to lead up to a transaction.

And then you would have to call through 

that data. But the data set is not as 

monumentally sized as it might have been in the 

past. So in the past if you were pulling all data 

for John Russo, for argument sake, for a period 

of three months, you've got this large dataset.

Today with the technologies that are 

available, and they are affordable, you can put 

some key words and some logic into your searches 

to say I'm searching for all of John Russo's email 

during this date range, but they might be 
communications that are only external to the 

organization, and with these key words put in the 

transaction id number, you can put in logic, like 

ands and ors and proximity this word within this 

number of words of the other, and you can cold down 

your dataset.

And that is where the power of the newer 

available technologies comes into play and I 

think would be a resource for most organizations 

today, you know, meeting these regulatory 

requirements.

MR. PERRY: Katie, I -- Eric Perry. I 

think it's important to take a step back here, and 

I hate to get too far down in the weeds, but to 

realize that, again, as a cash commodity 

merchant, we have a book of derivatives that 

manage risk and we have a book of cash. We don't 

tie those two together except as net positions at 

the end of the day. So as we through the day, in 

our shop, buying and selling cash commodities, 

that individual merchant may or may not lay off 

that risk at the same time they do the trade.

They may have already had a position 

that wasn't even so maybe they needed to buy some 
more corn or sell some more corn and that evened 

out their position, or maybe they actually pick 

up the phone and give that futures order to a 

central order desk that then executes it on the 

exchange, whether that be Minneapolis Grain 

Exchange or the Chicago Board of Trade.

But we do not keep that -- that 

commodity interest transaction and that cash or 

forward transaction. We don't tie those 

together by any number. We just -- we don't do 

it. We don't have the need to. We keep the 

pertinent economic terms of the cash trade 

because we'll need that in the future should we 

be in an arbitration case or a litigation and we 

have our derivatives hedging book.

But we don't match those up. I mean we 

don't take a 5,000 bushel corn trade that happened 

with (inaudible) in the middle of Nebraska and tie 

it to a 5,000 bushel corn contract that was 

executed on the Chicago Board of Trade at X price. 

That's -- that's not what we -- we don't need that 

kind of detail in our business. We don't need it 

to manage our business so we don't track it.

So I don't -- I think the gentlemen that 
have the technology, I think capturing all of this 

information in aggregate can be done, but again, 

bringing it all together is a significant 

challenge for our business.

We don't need to do it; we haven't done 

it in the past. So it's -- it's changing the way 

we do business. It's going from the least 

efficient -- the most efficient mode of operation 

to a much more structured and higher cost mode of 

operation.

MR. KEMP: Todd Kemp with the National 

Grain and Feed Association. We represent about 

1,000 companies nationwide, about 7,000 

facilities that handle grain or feed 

manufacturers or seed processors and these are 

the traditional agricultural hedgers.

Eric's firm and a couple of others 

around the table happen to be members of our 

association as well. But you know, what Eric is 

describing is exactly right and it's extremely 

widespread.

If you think about 7,000 or 10,000 

overall facilities that potentially could have 

been affected -- we -- we were encouraged when the 
final rule was published that the majority of our 

member firms, you know, had their problem taken 

care of on the cash side. And we appreciated that 

but there are still a number of firms who are 

members of a DCM who are affected.

One of our concerns all along has been 

that what we're looking at here is kind of a 

bifurcated marketplace where we've got DCM 

members who are required to capture this 

information and then you've got other firms that 

are not required to capture it.

And you know, if you're a farmer and 

you're talking or texting to your elevator, who 

do you want to do business with? The guy who has 

to tell you hey, this is all being captured for 

posterity in CFTC or the guy down the road who is 

not?

So I don't know if that goes directly 

to your point, but we -- we do have some concerns 

about an uneven situation being created in the 

marketplace.

MS. DRISCOLL: So I just -- some very 

good points were raised in terms of different 

parts of the rule. So I just wanted to focus on 
a couple of them. And at first we were talking 

about the definition of related cash or forward 

and I was -- but then also I think what we're 

talking about in connection with that is the 

definition of member that applies to the rule. 

So just to take us back to related cash or forward, 

do you have any suggestions for --

SPEAKER: Okay. So tell me -- so I 

can't minimize this screen? And how do I go 

back --

MS. DRISCOLL: Can someone -- can you 

please mute your phone?

SPEAKER: Okay. So just --

MS. DRISCOLL: Is there somebody who 

can help with this? Please mute your phone, 

whoever is on the line that we can hear; okay. So 

if anyone wants to speak to that.

MR. KOTSCHWAR: Katie, this is Lance 

with Gavilon again. I guess -- let's -- let's 

just assume for the moment that we can come up with 

something that's somewhat affordable to be able 

to track all of our related cash transactions back 

to futures.

I guess from my perspective, you know, 
I know we've touched on the issue of what -- what 

member it is. I don't -- my company doesn't have 

a fiduciary duty. We're, you know, 

we're -- we're grain merchandisers. So even if 

we collect all of this, what are we going to do 

with it? We're not -- I don't know what you would 

do with it. It's not -- it's -- if you go back 

and look at the way the history of member is with 

the fiduciary duty and having, you know, 

responsibilities to track something for a 

customer, it makes perfect sense because you had 

two ways to do it.

As your customer, a hedger, or a 

speculator; if your customer is a hedger then you 

would expect there to be some sort of 

related -- paperwork related to the -- to the 

physical side of that. But for us, because of 

this application of member in this instance, we 

don't have that relationship and so therefore, 

we're -- we -- we can't pick and chose on this; 

we're just going to have to record everything. 

We're going to have to collect all of this stuff.

It's going to be -- it's useless for us. 

I -- I'll -- we can talk about that more later when 
we talk about implementation challenges because 

I'm collecting -- I've been collecting instant 

messaging for two years; never once looked at it.

Doubt if we ever will because from our 

perspective, the Commission has a much better way 

of -- of figuring out whether they want to come 

ask us any questions with our large trader reports 

and our monthly 204 reports. We're -- we're a big 

company and we have lots of positions.

You can figure out from our other 

reporting whether or not, you know, you want to 

come knock on our door and give us a special call 

and ask us anything in particular, but I just 

don't see this -- even if it was affordable, I 

don't know why we would ever -- anyone would ever 

want to look at instant messaging and text 

messaging related to hundreds of daily 

transactions leading to cash contracts that are 

net hedged at the end of the day. I can't 

find -- I can't see that being useful information 

anytime.

MR. JESKE: I would add to that. I 

think the history of 1.35 is actually 

informative. That's why I mentioned it earlier. 
And I don't think you can really bifurcate the 

concept of who it's aimed at from this concept of 

related. And this -- this related -- or the other 

language that sneaks in is -- leads to the 

execution of a transaction and a commodity 

interest to a related cash or forward.

So to -- to expand on your question a 

little bit, that language was nowhere in 1.35 

before these conforming amendments so to speak. 

If you could look back in -- in time and back to 

'48, the reg said FCM and members of a contract 

market shall keep records of futures or cash 

transactions made by or through him. Him, the 

person in the pit.

Those are customer orders, again. So 

where this expansive related language comes in, 

to me is rather misplaced. As an energy 

end-user, we have people out in the field. As we 

all know there's a huge energy bloom right now by 

virtue of the fracking.

You have people out in Eagle Ford, 

Texas, who are texting because that's the mode of 

communication. They are primarily responsible 

for finding the crude out in the field, bringing 
it to market, whether they do so by train or pipe, 

and the ability to be able to go out there and make 

deals and make transactions with those people in 

the field, is crucial to be able to supply the 

energy to America really.

But that doesn't happen seamlessly 

without the ability to pool that -- those 

resources and then bring them to market. That 

process requires price exposure. That price 

exposure, yes, it is hedged in the derivatives 

markets and the OTC markets. But to rest your 

head on related to and say all of those 

communications need to be captured, I think 

is -- is just simply overreach by the Commission 

and should really be looked at closely because 

again, it goes into the customer activities, as 

opposed to that which is being affected in the 

ring.

The ring is a dinosaur, right. 

Now -- now we're talking about ether space and 

electronic executions. I really question how 

this impacts SEFs more than it does probably DCMs 

but it impacts them both the same I suppose.

MS. DRISCOLL: So I think one of the 
fundamental issues that we're hearing about is 

the definition of member, which is what draws in 

I think a lot of market participants to the 

written record, keeping requirement, and then 

fewer market participants to the oral record 

keeping requirement.

But I would just be curious to hear 

about what you all think of as a member, as opposed 

to what our statute says is a member and our 

statute includes anyone with trading privileges, 

which is, I believe, the part of it that sort of 

draws in a lot of -- a lot of market participants 

who wouldn't otherwise think of themselves as a 

member.

MR. SEN: Thank you, Katie. I'm Robby 

Sen at Ameriprise Financial. Our subsidiary, 

Columbia Management, (inaudible) CTA. We're 

also a member of a SEF so we're pulled into 1.35A, 

both for the oral and written record keeping 

piece. And I think, as Jerry was saying, the 

legislative intents of 1.35, it's never meant to 

take in customers or anyone who's -- who's 

basically a liquidity taker, not a liquidity 

provider, and not an intermediary.
And I think as it relates to SEFs, one 

of the important points is that the final 

rulemaking of 1.35A was published in December of 

2012 before the final SEF rules were published and 

before the final -- first SEF rulebook was 

published.

So (inaudible) like us, who are 

registered as CTAs, had no idea that we would even 

be subject to this requirement because we didn't 

think we'd be members. And then as the SEF 

rulebooks came out, more and more of them had said 

that if you -- if you're -- if you're a market 

participant with trading privileges then you're 

a member.

Our view is that membership on a SEF 

with trading privileges should not make -- make 

us a member. We don't take customer orders, we 

don't deal in commodity interest and that dealing 

in commodity interest is highlighted in the rule. 

And I think we're having serious thoughts 

internally about whether we want to be subject to 

a SEF membership and it's for various reasons but 

1.35A is one -- a big part of it.

The rulebooks are onerous and that's, 
you know, probably a different conversation. 

But if -- if we're going to be subject to 1.35A, 

we're seriously going to consider other 

alternatives, trading different products, 

possibly using an aggregator.

And I think there's been some 

developments recently in the market with some of 

the SEFs even coming out and saying that the 

participant itself could be an account, so like 

a neutral fund and not the investment advisor 

would be a participant.

I think one of the main reasons is that 

people want to get out of 1.35A and I don't think 

that's one of the intents of the rule; it's to pull 

in, you know, people that don't take customer 

orders.

MR. WALDMAN: If I can just echo that. 

I'm Steve Waldman. I'm a Managing Director and 

Deputy General Counsel at Tudor Investment 

Corporation. We've been registered with the 

CFTC as a Commodity Pool Operator and a Commodity 

Trading Advisor since the mid '80s.

We're also registered with the SCC as 

an Investment Advisor. And we've also -- we're 
also a member of the Managed Funds Association 

where we've been dealing with this issue on a 

regular basis over the past year.

Again, I -- just to follow up on what 

Jerry and Robby have said, I think the definition 

of, and what it means to be a member, have changed 

over the years. Initially when -- if you look 

back a few decades ago, what it meant to be a 

member of a DCM was if you're acting basically as 

a FCM or (inaudible) in some intermediary 

capacity. And I -- probably the trend over the 

last decade or so has seen more entities become 

members not in their capacity as an intermediary, 

but solely to get better rates on the exchanges. 

And I think that's played a big role.

And then when the SEFs -- SEFs were 

initially proposed and introduced, nobody really 

had any idea what it would be to be a member of 

a SEF. Nobody knew if you would have to be a 

member of a SEF. And then for -- when rule 1.35A 

was proposed, it really seemed as a nonevent for 

many in the industry because nobody anticipated 

ever becoming a member of a SEF.

So it was only after 1.35A, as Robby 
mentioned, after 1.35A was adopted, that the 

rulebooks were finally published. And even 

today, it's not entirely clear if you're a 

participant on a SEF, if that makes you a member, 

if you have trading privileges does that make you 

a member.

And I have to say that it's 

probably -- it's difficult to say that anybody who 

was really given a reasonable opportunity to 

comment on 1.35A, given that the rule came out 

prior to SEFs, we just had no idea what it would 

mean. And what may have been viewed as a 

technical amendment, and in certain instances 

really turned into a substantive change to the way 

many of us are forced to do business.

MR. CORDES: Katie, if I can add just 

a little bit of clarity too. Scott Cordes with 

CHS Hedging. We're registered as an FCM but I 

also represent our parent company that has 

probably over 200 locations buying grain around 

the countryside. We also have customers that 

are, you know, probably a couple hundred other 

cooperative elevators who are buying grain as 

well. So they're quite interested in this 
related cash, how it plays out.

And as some of my other colleagues 

talked about, you know, they're looking at their 

aggregate positions every day, typically 

handling customer orders. But some of those 

folks are members of exchanges and this is the 

part that causes some heartburn; what does that 

mean.

Typically in the past they become 

members to have some input around the -- the 

hedging and viability of those contracts in good 

order, but also for their volume, such for around 

exchange fees and what they're paying. So there 

was a reason for that.

Are they trading directly on those 

exchanges? Typically not. They're -- they're 

placing orders through an FCM like ourselves, but 

they're starting to ask themselves should I 

continue to be a member because now I get captured 

in some of these rules and with some of the areas 

they're operating in and the advent of 

technology, people want to use a lot of different 

social media to communicate; it's hard to comply 

with that on a cost structure that's cost 
effective for them. So that's some of the 

clarity that we see on the grain side of this 

issue.

SPEAKER: I was going to make just one 

comment. I think it might be important to point 

out again, which I think is an obvious one, but 

the purpose I think, at least as I envisioned it, 

when this rulemaking was being considered, the 

real purpose behind this rule was that it -- that 

it enhance the capabilities of the enforcement 

division.

This is an enforcement rule more than 

anything else. So it has both a deterring effect 

through any of these complying, but it also has 

the effect of assisting, with respect to 

investigations, if one is initiated. So I don't 

think it's -- it's difficult to argue that there 

is any legitimate public policy purpose behind 

the rule.

The real question here I think is, are 

there other public policy objectives that are 

somehow forwarded given the scope of the rule and 

upon whom the burden lands. And to me that's 

really the most important question. I feel like 
we're talking about that a little bit.

But I just wanted to point that out 

because I -- there is some utility, even if, let's 

say hypothetically, there's a -- there's an 

enormous amount of records kept, oral records, 

even written ones, that never get read.

I think there's still some purpose 

behind the mere requirement that the records be 

kept. Again, the better question is, is the 

scope correct. Is the cost benefit analysis 

working out in favor of the scope of the rule 

that's current drafted?

So I do think, you know, we're here to 

solve problems but even if we were to do nothing, 

you know, I think it is, again, important to just 

say that there is some -- there is some purpose 

or utility behind the rule even as it -- as it is 

written now. But -- but what we want -- what we 

want to make sure is whether we've got that 

balance right, whether we've got the scope right. 

So enough on that for now.

MR. O'MALIA: Can I follow up on that 

a little bit? Because I think what Robby 

mentioned -- if membership on a SEF dictates who 
has to record and who does not have to record and 

people choose to either use alternative means or 

they go through an introducing broker of some sort 

or aggregator, then you're going to create an 

incentive not to record.

So is the right answer under your 

scenario, Mark, to apply that and have the 

introducing broker there for a record, all of its 

customers, when this was a customer rule as 

opposed to a membership -- this is all very, you 

know, we've -- we've clearly identified 

workarounds to avoid this thing that I don't think 

were contemplated or priced into the cost benefit 

analysis when that was done.

And then to your point, if keeping all 

of the data is important, how do -- how would you 

address the work around issue that -- that is an 

obvious issue?

MR. WETJEN: Yeah, I think that's a 

great point and it relates to what I said about, 

you know, whether there might be other policy 

objectives of the Commission that are somehow 

thwarted by the current scope of this. And 

obviously we want to see as much participation on 
SEFs as possible and so to the degree the current 

construction of the rule is standing in the way 

of that, that's something we need to take a 

careful look at, which is part of the reason we're 

here.

The other thing I would add is in 

talking to some of the asset managers in recent 

weeks about this, -- and I'm not sure whether it's 

on the list of questions but it is something I 

would be curious to hear some thoughts from the 

group on.

If there's duplication in the record 

keeping in any sort of meaningful way, in other 

words, if we know a conversation let's say is 

captured by one of the participants in the 

conversation, so we know the conversation is 

recorded by someone, is it necessary that both 

parties are keeping the same recording. I'm not 

so sure.

I mean just the mere fact that you know 

that someone you're talking on the phone with is 

recording the conversation is going to have some 

impact on what you say; at least in my experience.

MR. O'MALIA: Well that gets back to 
the customer member relationship again and that's 

broken down in this rule. I mean it just doesn't 

function the way it was supposed to function. 

Maybe (inaudible) can reflect on what the -- how 

you intended, kind of, the SEF rules to serve on 

this and what the appropriate membership 

requirements were and what you intended to 

capture. Maybe, David, you weren't the right guy 

to ask. I do note that none of the people who 

wrote this rule are at the table.

MR. STEINBERG: I --

MR. O'MALIA: Oh, you were there, yeah.

SPEAKER: -- follow up on and we can 

discuss at another time. It's certainly 

something we can follow up on and check with the 

appropriate people on that.

MR. PERRY: But I think this is a good 

line of conversation because it does -- and we can 

tie in here -- there's a bit of an inconsistency 

as you think about these records and you think 

about the carve out on the oral. So on the oral, 

for our organization, that's not a registrant, 

there's a carve out for oral recording. We're 

out of the oral recording piece.
But yet, we're still handcuffed to the 

electronic written record keeping rules. The 

obvious answer for us in that environment, and 

this is not to skirt the -- to skirt the policies 

because we want -- we want to work with the 

Commission to -- to make this rule workable and 

to make the market better for everybody. But the 

obvious answer for us is to push all of our -- all 

of our trade to -- to the phone; to just simply, 

through policy action limit the conversations 

that take place about the related cash or forward 

transaction to the phone. And there won't be any 

of it that will be recorded.

So there seems to be, along those two 

lines, the information is either important or 

it's not. And we've worked with the Commission 

in the past, specifically on the Chicago wheat and 

Kansas City wheat convergence issues, and we've 

extracted from our systems all of the cash 

information to help the Commission determine what 

was going on with convergence in those futures 

markets.

And I think, through working together, 

came up with good, you know, good answers in that 
arena with relevant economic information. It's 

economic terms of the trades, the contract 

prices, the basis, contract amendments, but not 

this enormous amount of dialog that happens every 

single day. Let's get down to what really makes 

a difference.

MR. WALDMAN: So if I can just respond 

to that as well. I absolutely agree with 

everything that -- that Eric said and if there was 

a policy reason to push trading onto SEFs, this 

is a disincentive for people to actually do that 

trading.

Just to respond to the question about 

asset managers, there's a specific carve out that 

was written into the rule for exemptions for 

commodity pool operators. And for whatever the 

policy reason that the -- whatever policy the 

Commission is following and pursuing that 

exemption, it's not clear to me anyway, why a 

commodity trading advisor wouldn't be similarly 

exempt. I -- I just haven't been able to find a 

distinction in policy between the two.

MR. SEN: And -- and just to add to the 

point of duplication. I mean I think as us as a 
SEF member and looking at our commodity interest 

trading, anything that we do on an exchange 

through a SEF is subject to the SEF record keeping 

rules and the SEFs imposed record keeping rules 

on their members and participants.

And every single other bilateral trade 

we do that's often exchange is with, presumably 

with a swap dealer who's subject to the part 23 

rules or 1.35. So those conversations are 

getting recorded. And I think this -- this goes 

towards the interpretation of the rule.

Where the rule says provided or 

received and (inaudible) of execution of a 

transaction, I mean we're interpreting that to 

mean external communications. So if our 

portfolio manager talks to our trader about an 

order they want to do for an account, we don't 

think that should be recorded but I don't think 

it's clear from the rule that that's the case. 

And so that's just one of the challenges that 

assamanders face in trying to comply with the oral 

record keeping rules and why we -- I mean, 

if -- first we think there should be some 

exemptive relief.
If not, we think the no action relief 

that was provided up until May 1, should be 

extended because it's pretty hard for us to be 

able to comply and know what the costs are when 

we don't know what the scope of the role is.

And then if it does lead to less 

assamanders accessing stuff directly, I mean I 

think it'll go against congressional intent and 

the intent of the Commission to increase 

liquidity and transparency in the market, which 

was what the SEF rules were intended for.

MR. JESKE: I think the concept of cost 

was addressed. I don't know there was a cost 

benefit analysis done in this conforming 

amendments. It may have been done but I really 

don't think --

MR. WETJEN: We do one at every rule and 

we're required to.

MR. JESKE: Well, I guess I wonder 

if -- if that cost benefit analysis, given the 

fact that the amendment to 1.35 was driven by 

enforcement, was done in a way that really 

evaluated the cost associated. So I think you 

brought up a concept of if one party keeps the 
communication and another party does not keep 

that communication, is that okay, is the 

redundancy necessary.

The cost of keeping isn't the end of the 

story. The cost is -- is much greater than that 

because when you're looking at archiving 

information for five years in some searchable 

format and then surveilling that information, if 

you're a U.S. corporation following the U.S. 

Corporate Sentencing Guidelines, there's a 

surveillance cost associated with that.

Human resource costs, systems cost; in 

addition, when you get that lovely letter from the 

enforcement that asks for that information, you 

have to employ council to go through all of that 

information. You have to search that 

information for that which has been requested.

Those bills are extremely expensive. 

So the cost associated with 1.35 doesn't just stop 

with archiving it and sticking it into a cloud 

some place. It's much greater than that. And I 

really don't think that that part of the cost 

benefit analysis was really addressed. And it 

would be something that I think anybody would 
ultimately face if asked for that information 

down the road, being maintained for multiple 

years.

There's another point, too, with regard 

to SEFs and -- and the mistake that I think is 

occurring in Europe with the multilateral trading 

facilities and how a derivative contract is 

deemed within scope. Many folks who used to 

participate on electronic screens are now going 

to the phone as -- as Eric mentioned.

Similar to SEFs here, if the goal is to 

participate in SEFs, who are glorified voice 

brokers, there seems to be a disincentive to use 

their electronics matching systems, or any 

systems for that matter. And why not just do it 

the good old fashioned way and continue to speak 

over the phone.

Now certainly the Commission could come 

out with another rule amendment, which would 

capture audio, but I think we all know the cost 

associated with audio and searching and 

surveilling for audio, which is astronomical.

MS. DRISCOLL: Maybe Mr. Powell, this 

might be a good place for you to --
MR. POWELL: Good morning, Robert 

Powell from Etrali Trading Solutions. We 

provide voice recording integration for fixed 

line and mobile call recording. Our business on 

the mobile side started up in Europe a couple of 

years back when the FCA introduced that and 

actually we have cloud based solutions for both 

fixed line and mobile recording globally now. So 

based on the AT&T network over here.

I think the -- in terms of cost you make 

some very good points about the total cost of 

ownership not just being the capture. And I 

think there's also been some good points made 

about not storing for storage sake. I think 

that's a very important point. I think we have 

really witnessed some major changes in the way 

that the total cost of ownership has been driven 

down over the past few years, particularly to do 

with voice, which is about 12 times greater the 

volume of your electronic communication.

So I think the solutions that are now 

out there in the market give you some very good 

ways of accessing that data from the method data 

to allow you to match a conversation to a 
transaction and also give you some very good ways 

of actually searching inside that data without a 

huge expense. So I think there are solutions out 

there now and they can range from smaller 

solutions to larger solutions.

MR. JESKE: So that's converting voice 

to text, yeah?

MR. POWELL: We -- we tend not to go 

down the converting voice to text route. We 

allowing searching inside the conversation. The 

conversion is problematic. Being able to search 

inside it is a better way of doing it.

MR. JESKE: Yeah, it's very 

problematic. In terms of being able to archive 

that information though, I think we're stuck with 

the same thing, when's a deal is a deal. And how 

do you reference a transaction id to something 

that isn't even a deal yet?

MR. POWELL: Yeah, I think we've heard 

from Mr. Russo this morning and I think there's 

a number of different elements of this, which I 

think are kind of coming together. There are a 

lot of conversations in the market which are not 

about an actual transaction.
You know, if you're -- a lot of the 

conversations about the relationship management, 

about maintaining your relationship with your 

customers, with your counterparties in the 

market. However, there are also conversations 

which indicate pricing or which would lead to 

transactions.

I think it's impossible to try and go 

down the road or pressing a button on your phone 

or on your email to say I'm just about to talk 

about a trade that might happen in the future. So 

to the extent that you are recording everything 

or you're capturing all of your data, I think the 

tools give you some very good insights into the 

way that you can call down very quickly to a level 

where that reduces your total cost of ownership, 

particularly for those investigations.

So if you get to the point where you've 

got an investigation about a particular custodian 

with a particular counterparty or a particular 

transaction, and to your point about the cost of 

the legal fees involved, I think you can get down 

to a point where the severely reduced number of 

conversations that you're actually going to be 
giving to the legal counsel and then on to the 

Commission can really be called down quite 

quickly.

MR. RUSSO: Yeah. And I just wanted to 

add, you know, with respect to storing all of this 

data and whether it's actually useful to any 

organization, I -- I think with respect to 

litigation support, it's an asset that every 

organization has to have all of their data 

archived.

The large majority of organizations out 

there are not doing illegal transactions. 

They're not violating laws that they're getting 

accused for. And if you don't have the archives 

and you have nothing to go back to to justify your 

position, I think that's more costly than not 

storing the data and spending a few dollars a 

month.

Yeah, is it an extra hoop? I 

absolutely agree it is an extra hoop and it's 

probably something that -- that if you're a trader 

or a broker or you really don't want to deal with 

these complexities, but it's just a fact of life 

today. Everybody's got an electronic device, 
whether it's a Blackberry, an Android phone, or 

an iphone.

That if you honestly believe that these 

communications are not occurring, I think we're 

putting blinders on. It's something that we have 

to address moving forward.

MR. POWELL: I'd like to add just one 

point to that, which is in terms of having this 

data and using it usefully, we're seeing quite a 

large emergence of what we call voice 

intelligence which allows you to link the data 

that you have and the way in which it's been 

collected into your CRM solutions to allow you to 

manage your business better. So this is not just 

about necessarily complying with the rules.

You can now get intelligence from that 

data about the cost of doing business with a 

particular client, how many times you have to call 

a particular client to get a trade. So there are 

other reasons why you might want to keep that data 

apart from -- to get for regulatory reasons.

MS. DRISCOLL: Lance, I think you 

wanted to say something.

MR. KOTSCHWAR: I do. I want 
to -- just to reel this back in from those of us 

in the membership area who are really just 

customers and end-users. Let's take a typical 

conversation that Eric and I are going to have. 

He's a farmer. I'm a merchant. He's going to 

call me up and ask me what I'm paying for corn 

today. I'm going to tell him, he's going to offer 

me, say well what if I give you this many bushels, 

we'll arrive at a deal, right. We're having it 

right now. We can have that conversation on the 

phone. I'm going to follow it up with a contract, 

probably -- it'll satisfy my need to have business 

records.

Today, what -- and this is a challenge 

for us; okay. That's going to be the large part 

of our origination business. It's conversations 

with farmers. Today, most farmers, or many 

farmers, would prefer to have exactly that same 

conversation by a text. It's a lot more 

efficient and that's the struggle we're going to 

have.

If -- if we're not going to distinguish, 

there's -- there was a policy reason why you 

created an exemption for oral recording for 
people like me, leaving aside for the moment how 

we got here with all of this membership history, 

but you're -- you're forcing me to do something 

the 20th Century way on the phone because I 

just -- I can't, especially with the mobile 

devices. Despite all of this, I'm not going to 

take that step yet.

You know, grain origination is a fairly 

low margin business. I'm not going to get this 

high tech about it. We're talking about exactly 

the same conversation and if I do it on the phone 

it's an oral communication.

If it happens over the same phone via 

text messaging, it is now a written document that 

I have to record and that's -- that's inconsistent 

and it's just -- it's one of the things that's 

driving us crazy.

MR. WETJEN: I agree. That seems odd.

MR. KOTSCHWAR: Very odd.

MR. SMALLEY: I'd like to add a point --

MS. DRISCOLL: Can --

MR. SMALLEY: -- similar to Lance's but 

from a different perspective. My name is Eric 

Smalley and I'm from Growmark. We're a regional 
agricultural cooperative and we serve about 

250,000 farmers in the Midwest and in Ontario, 

Canada. We also operate MIDCO commodities. 

We're a small non clearing FCM that serves price 

management needs for grain elevators and their 

farmers.

So we're in the smaller end of the 

spectrum but we have some of the similar issues. 

On the one hand we're very thankful that we've 

received some relief via a no action letter for 

our branch office operations because they're so 

small and the cost effectiveness isn't there. 

But then even in our home office, we -- we've got 

similar issues where it's changing how we do 

business.

We've already got record keeping 

requirements and our phone lines are already 

recorded. So to -- when -- to terms of technology 

and whether it's affordable, I would say it's a 

relative term and for a smaller firm, that bar is 

a lot lower for us. And so it's hard for us, as 

a cooperative, to justify any additional 

investment in technology that's not going to 

bring value to our customers, solely to help 
enforcement issues that might or might not come 

down the road.

So we've been forced, at the moment 

anyway, that we drive all of our customers back 

to phone and email, things that are already 

captured. And so, you know, for that 

possibility, it's changing the way we do 

business, which isn't helpful for our customers.

MS. DRISCOLL: Can I just pose a 

question regarding the membership issue with 

regard to storage of written communications? 

There was a DMO advisory in 2009 that spoke to the 

written communications requirement and the fact 

that it was DMO staff's belief that that included 

emails, instant messages, and text messages, and 

I'm just curious to know how you all interpreted 

that advisory. It's five years ago, but --

MR. KOTSCHWAR: From my perspective, a

better question would be was I even aware of that 

advisory and the answer would be -- trying to be 

very diplomatic here; no. This became an issue 

when that -- that little -- that little bit of 

information got rolled into the final rule, okay.

I don't want to get into a lot of the 
other issues. This has given us angst and 

consternation over, but I would say that I 

don't -- I haven't talked to anybody who was even 

aware of it.

MR. CORDES: Katie, I would respond. 

As an FCM registrant, we got that advisory. We 

put in some changes to start recording our ims, 

that kind of things we looked at. But I would 

tell you from some of our customers' standpoint, 

that's a member of an exchange, I doubt they ever 

looked at it.

The Chairman's question about doubling 

up on some of this recording, I would say those 

folks that are a member of an exchange, they're 

derivatives activity, whether it's futures 

options or some sort of swap is going through a 

registrant, like ourselves, or capturing that 

information. So it sounds like why should they 

capture on the other side. There's probably some 

redundancy there that could be alleviated.

MR. JESKE: On page two of the 

advisory, the term member is footnoted, footnote 

four, which references 4G of the act; 4G of the 

act says FCMs, IBs, floor brokers, and floor 
traders. Does not say customer --

(Off the record.)

MR. JESKE: -- 2009, February 5, 2009; 

Division of Market Oversight.

MR. PERRY: And Katie, I think -- Eric 

Perry. And not -- not -- clearly wasn't -- didn't 

have any conversation with anybody on the 

Commission about the 2009 advisory whatsoever. 

And I think to Lance's point, I think Lance is 

right. I think those of us in the member space, 

at managing our own accounts, looked at that 2009 

advisory and our world of member is that person 

that has fiduciary responsibility and handles 

customer money. And right, wrong, or 

indifferent, I think that's probably how -- even 

if you were aware of it, as Jerry points out, I 

think most people would interpret it that way, 

most of us in our arena.

But I do think the footnote is telling, 

relative to the definition of member. And how 

far we've -- how far we've drifted from what the 

original intent of member was to where we are 

today in this GLOBEX screen trading world.

MR. KOTSCHWAR: Just to follow up on 
that a little bit, I mean we've heard all of the 

elements of where we think this needs to go thrown 

out today. You know, fiduciary duties, 

customer -- dealing with other customers' funds, 

whether you're otherwise required to be 

registered.

I mean those are three elements that 

separate all of us who have the most heartburn 

about this from anybody else. We don't 

have -- we're not otherwise registered. We don't 

deal with customers. We are the customer and we 

have no fiduciary duty. So that's -- seems like 

those are common elements to everybody who's 

really got rash about this.

MR. KEMP: Katie, one quick comment 

here. You know, as we step back a little bit and 

look at it from an industry perspective and the 

grain industry, for many years our industry has 

relied on cash generally being excluded from CFTC 

jurisdiction. You know, there is a cash forward 

contract exclusion. The Commission's oversight 

mandate is really in the futures markets, right.

Our members fear that if you're taking 

this deep a dive into cash markets on a regular 
and ongoing basis, you're really -- really 

blurring the lines between the two.

MS. DRISCOLL: So I'm just curious to 

know, I mean more from my -- the way my lawyer 

brain thinks, if there are places in the rule that 

you think could possibly be amended or if there's 

guidance that the Commission could give to sort 

of alleviate your heartburn, Lance.

MR. PERRY: So Katie, I'll go back to 

the 2009 guidance. I think -- I think that the 

term member in today's world doesn't fit anymore. 

I think that needs to be removed. Now I can't sit 

here and tell you that I have a confident answer 

on exactly what needs to be replaced with that; 

is that registrant, or is it that list of four or 

five that was present in the 2009 guidance 

relative to this kind of communication.

But I do think that's the most direct 

and most efficient answer to that. And to 

Robby's point, I -- I -- I may not be in the right 

spot, but I'm not exactly sure in the carve out 

why CPOs were carved out and CTAs weren't. I 

think there's a lot of issues around membership 

that need to be fine tuned and I think we probably 
need to go to a black and white list, like the 2009 

guidance did, of exactly who falls into part 1.35.

MR. WETJEN: I think the CTA exclusion 

was mostly based on the fact there's some 

semblance of a customer relationship there, 

unlike a CPO. And I'm not saying the analysis 

came out the right way, which is why we're here, 

but that was part of the thinking at the time.

MS. DRISCOLL: So maybe Robby or Steve, 

you could talk a little bit about -- I know you're 

both dual registered CPOs, CTOs --

SPEAKER: Katie, can I -- I'm sorry, 

can I --

MS. DRISCOLL: Yeah.

SPEAKER: -- it looked like you were 

about to -- because you touched on this earlier 

so I'm curious if you had a reaction.

MR. WALDMAN: Yeah, and I can't speak 

for obviously all in the industry because CPOs and 

CTAs come in all different sizes. And I think the 

answer would be that to the extent that you're an 

advisor that has discretionary control over 

money. I'm not sure there's such a distinction 

between a CPO and a CTA.
MR. O'MALIA: But you acknowledge that 

there is some type of a customer relationship, if 

you will, between the advisor, the CTA, and the 

customer, right?

MR. WALDMAN: Well, I would --

MR. O'MALIA: It's just the fact that 

there's discretion in the CTA; it makes it 

less -- it makes it look less like a customer 

relationship. Is that the point?

MR. WALDMAN: Well, that's part of the 

point. The other question is in that context, I 

have no idea what the difference between a CPO and 

a CTA is, just other than the nature of a CTA may 

have -- a CPO has discretionary authority over its 

funds, meaning its investment funds, a CTA has 

discretionary authority over its investment 

funds and its managed accounts. So it may be 

different for others. I'm just answering the 

question on behalf of Tudor.

MR. SEN: Yeah, I mean I think as a CTA 

we're -- we're acting as a fiduciary and managing 

money on a discretionary basis and I think that 

as I -- in the latest 1.35 rulemaking, the two 

overarching goals were customer protection and 
market integrity. And I don't -- in terms of 

customer protection, I don't see what 1.35 does, 

in terms of customer protection for a CTA when 

we're managing money on a discretionary basis.

The only question is if we're managing 

it based on the investment guidelines, not what 

commodity we're buying or -- and any sort of 

external communications as we've talked about 

have -- are being recorded. So I don't -- I don't 

really see the difference between a CPA or a CTA 

either.

MR. CORDES: Do we also need to address 

the September 30, 2013, what is a member on a SEF 

guidance as well, which seems to -- that's the 

direct access? That distinguishes if you have

direct access versus intermediation that 

automatically brings you into that obligation and 

makes some of these other distinctions irrelevant 

I assume.

MS. DRISCOLL: I -- I do think that 

would be helpful to address. I don't know if -- I 

would imagine that would be a Robby and Steve 

issue again, as well. And your thoughts on the 

guidance and how it relates to this situation.
MR. SEN: I mean I -- I still don't 

think it's -- it's clear what a member is and what 

trading privileges mean because if I'm accessing 

a SEF through an aggregator and I'm seeing the 

same view, why should I be treated differently 

than someone who's a direct member or if I -- or 

if, you know, I -- I'd tell someone else to execute 

the order on a SEF. Why I should be treated 

differently?

I mean I still think that trading 

privileges hasn't been defined and I think some 

clarity on that would help -- help the industry 

a lot.

MR. WETJEN: We don't have multiple 

definitions of the same term but, you know, 

another way to go about it would be defining 

membership as it relates to 1.35, right?

MS. DRISCOLL: Unless anyone has 

anything else to comment on the membership issue, 

I just wanted to go back to the lead to the 

execution of a transaction language and hear from 

folks on how you're viewing that language today 

since we did not define it in the preamble to the 

rule.
MR. PERRY: I'll take that, Katie.

MS. DRISCOLL: Okay.

MR. PERRY: I can tell you how we've 

been advised to interpret that. That it's any 

conversation, however it takes place. If it's in 

electronic written format we have to capture it. 

But it doesn't matter what mode it takes place in, 

but it's a conversation that ends up, like in 

Lance's example, you know, a negotiation between 

a merchant and a farmer buying some grain off of 

the farm or a negotiation between a merchant and 

an end-user that's buying trains to feed chickens 

in Alabama. But it's all of the dialogue that 

actually ends up resulting in the consummation of 

a trade of a cash commodity.

That's how we've been advised to 

interpret that. And back to kind of where I 

opened up, and it's hard to draw distinct lines, 

you know, in the language. We're going to quit 

talking about this, you know, it all kind of 

bleeds together. But where I started in my 

introduction was that basically -- there are 

some -- there are some conversations that take 

place about, you know, customer management, 
customer relationships, that aren't directly 

related to a trade but you can't figure out which 

one that is or isn't when you -- when you start 

to write the email.

But that captures everything. So the 

way we've been advised to interpret that is that 

all of the dialogue needs to be captured. Now, 

in a meeting, and I'll get the date wrong, but I 

think it was here with the Chairman this month 

last year or right there thereabouts, we had just 

this conversation and I think what we as an 

industry, or the participants in that meeting 

heard, was well that's not exactly the intent; 

okay. Can we get guidance on that? And we 

didn't get that.

And I know that there's a massive 

backlog of stuff and everybody's busy. But 

that -- in absence of any definition or formal 

guidance on leads to, we've been advised that it's 

any conversation that takes place that ends up in 

the actual consummation of a cash commodity 

trade.

MR. KOTSCHWAR: Katie, I'd like to just 

go a little bit further on that. So how we are 
doing exactly what he just said because we've 

gotten the same advise is, we are, of course, 

we're keeping all email for anybody who's got the 

ability to sign a merchandising contract on 

behalf of us, we're keeping all instant messaging 

but we're forcing all instant messaging to be 

originated from systems that we can capture.

So the flipside of that is we are, on 

purpose, specifically and very focused, none of 

our merchandisers are allowed to use mobile 

devices for anything other than phone calls. If 

they want -- when it comes to talking about cash 

commodities. That's -- those are our rules 

because we cannot comply with the mobile devices.

We can capture everything else, which 

I told you we've been doing for a long time now. 

Welcome to come see it; I'm sure it's gigabytes 

of data. But we just simply can't do it with 

mobile devices yet so we've complied by not using 

it.

MS. DRISCOLL: And Lance, is that 

because is prohibitively expensive for you to 

keep the text messages?

MR. KOTSCHWAR: Well, I'll give you a 
perfect example is iphones; lots of people have 

iphones. The -- the -- I talk to our tech people 

very regularly about this and I say hey, is there 

any new systems out there that we can capture the 

imessaging. And I -- I am told that imessaging 

is absolutely proprietary; there's no way to copy 

it other than to make a copy of your screen and 

email it to yourself as a gif file.

So we don't know how to -- so again, 

that's -- there maybe some off the shelf systems 

to -- that we can run into with that, but it's a 

lot more effective for us to just say don't use 

them, which again, that puts us at a competitive 

disadvantage with our competitors who get to text 

with the farmers. We only get to talk to them.

MR. SMALLEY: Our issue is similar, but 

then also we didn't go that direction because then 

we -- we knew we had no way to index those 

conversations to a particular transaction 

anyway. So we -- we went the similar route, 

partly due to cost, but partly because we knew 

there was no way, currently anyway, to be able to 

index all of those conversations to a particular 

transaction.
MR. RUSSO: Yeah, what we're seeing is 

a lot of companies are putting in company policy 

to their employees saying that you can bring your 

own device and use it for business purposes, but 

it must comply to company policy and standards and 

right now that's mostly limited to Blackberry 

devices and Android devices.

As Lance had mentioned, Apple has not 

released its APIs to any vendor so we cannot 

capture ios related text messaging. So most 

every company that we've dealt with has basically 

just said you cannot use your iphone for business 

and you're limited to Android or Blackberry and 

usually it's company provided equipment so this 

way you could put the controls in place.

But if there's one thing I could ask, 

you know, the regulators to do is sort of, you know 

tap on Apple's shoulder and give them that extra 

nudge that they need to get on board because every 

other vendor has done what they've been required 

to do.

MR. POWELL: Yeah, I can -- I can really 

echo that. We've had dozens of conversations 

with Apple directly and they are fiercely 
resistant of opening up this capability.

We've -- we've introduced the fact that 

the market is generally, and not even just the 

futures and commodities market, but the financial 

markets globally are interested in using their 

devices and would be delighted to be able to 

capture this for all of the reasons that they need 

to on the record keeping side and have not been 

able to make much headway with them so far.

MR. CORDES: Yeah, I would just echo a 

few of the comments too. We've put in some policy 

within our FCM that -- for employees using cell 

phones and it's not allowed for company business. 

Some folks need to take calls on off hours, that 

kind of thing. We're providing them with a 

separate cell phone or a tracking type device.

But really we've encouraged the 

business takes place in the office, well that's 

hard when markets are trading 24/7 and somebody 

wants to talk to their personal broker that 

they're comfortable with. It's hard to stop 

those conversations. But we've really had to 

really entrench back and -- and you're not able 

to use all of the tools that are available out in 
the marketplace is really what's happening.

MR. KOTSCHWAR: Just one last thing and 

this goes back to the way Eric described -- the 

way he has a physical book and a derivatives book; 

same with us. So this notion about what does it 

mean to be indexable and searchable, we do 

hundreds of physical transactions each day.

At the end of the day, we'll probably 

do some derivatives transactions. We may be 

doing it during the day. The only thing we can 

do is we can capture all of that instant messaging 

by day and by person. We can do it by day and by 

person and that's as close to indexable and 

searchable as we can get. To try -- because of 

all of the challenges of trying to tie those back 

to a particular derivatives transaction, we don't 

keep our books that way so we will have all of this 

information by person, by day. That's it.

MS. DRISCOLL: I think we've hit most 

of the points in the outline that I provided to 

all of you but if there are some issues that you 

feel like we haven't covered and you'd like to 

raise them, please do.

MR. PERRY: Katie, I want to -- I want 
to echo what Todd touched on a little bit. 

Relative to leads to the execution of and 

capturing all of that information, whether it's 

in a -- whether it's in an im or a text or via 

email, and again, this goes back to the membership 

thing and I think everybody gets that. But it 

does -- it's -- I don't think you can measure it, 

quantify it in dollars and cents exactly.

But in this age, with all of the, you 

know, what we've seen in the news over the last 

12 months about phone calls being recorded and, 

you know, all of that sort of stuff that's been 

in the news, we do feel like those of us that are 

getting caught in this membership net are kind of 

at a disadvantage because we're doing business 

out in the country with the next three competitors 

that don't have to do any of this stuff, none of 

it.

And the -- and when those customers know 

and hear in the press that hey, the Scoular 

Company is recording everything we do; if we send 

an im to them, I'm not doing that anymore. Okay; 

well, if you -- like Lance points out, if you 

prefer to communicate like that, you know, you're 
in the shop or you're on the combine and you want 

to do it then you're probably going to do it to 

the guy next door to us because, you know, he's 

not going to record it.

He's -- he doesn't have to capture it 

because he doesn't get caught in the net. So I - I 

do think that creates -- disadvantage is a strong 

word. It creates concerns for us in the 

marketplace, given how we've bifurcated the 

people in our business with record keeping.

MR. CORDES: I was just going to add to 

it and maybe it comes back to the question of, you 

know, what you're trying to capture or what's the 

end goal in this whole thing. And I look at the 

marketplace today and most of your derivatives 

transactions are taking place electronically.

There's a front end system out there 

that's capturing a lot of this stuff so I'm not 

sure what everything else is going to do other 

than point you where that trade is at, the time, 

and when it took place. But a lot of that 

information is already captured as far as when it 

traded, and how much, and that kind of thing if 

that's what you're after.
MR. JESKE: Well, I think it's pretty 

clear that the rule as it's written today is a 

disincentive to become a member of a DCM or a SEF. 

I know we're in a SEFed economy where we're 

dealing with (inaudible) classes that don't have 

anything to do with energy or grain at this point.

But if the Commission's public interest 

is to see participation in SEFs down the road, I 

think this rule needs to be amended because, you 

know, we have no interest in being part of a SEF 

at this point and if that's a public policy 

concern, then maybe the Commission 

should -- should try to address this in a 

constructive way to create liquidity.

MS. DRISCOLL: One of the carve outs in 

the amendment was for small introducing brokers 

and it was the only area where we applied a size 

limit and I'm just curious to hear if that would 

be effective for any other market participants. 

We actually ended up cutting out I think about 95 

percent of our registered introducing brokers 

with the carve out.

MR. JESKE: Katie, I think that goes to 

cost. And if there's a proper cost benefit 
analysis done, then that would be great. But 

some of the costs that I mentioned before, I 

highly doubt if they've been evaluated. 

Because -- just because you get a request letter 

from the Commission, there's a cost associated 

with that.

It doesn't mean you've done anything 

wrong, but you're compelled to review and search 

and lawyer up. And if you don't, you -- you -- you 

run the risk of providing reams and reams of 

information that haven't been thoroughly 

reviewed. And you know, again, query U.S. 

sentencing guidelines.

If you're not already reviewing that 

and then you do get, you know, the rogue trader 

so to speak or somebody in the organization that 

shouldn't have said what he or she said at that 

particular point in time, because let's be 

honest, that's what -- that's what's being looked 

for.

I don't -- and I'll do different, Scott. 

I don't think they're really looking for the deal 

execution. They're looking for more. And 

if -- if enforcement was the motivator behind 
that, well, I think there has to be a balance and 

I think the pendulum swung a bit too far.

MR. KOTSCHWAR: I would just say with 

respect to using some kind of a size gauge that 

I don't think that would be effective at all for 

companies similarly situated to us because that's 

one of the reasons we are a non registered 

member -- non registrant member of a DCM is 

because of our size. Because we want to take 

advantage of the economy to scale of -- just kind 

of trading rights.

So you're going to -- all of the ones 

that are having this problem are going to probably 

be in your size. So I don't think that -- that 

would not be an effective way to distinguish among 

companies like us.

MR. SEN: Yeah, I would tend to agree 

as well. I mean for a CTA, you could be a one 

trillion dollar -- have one trillion dollars in 

assets under management but if you're doing ten 

million dollars worth of derivatives trades, that 

doesn't mean your call should be recorded and 

someone else shouldn't. So I don't really know 

if you could really get the proper size metric to 
exclude who you should.

MS. DRISCOLL: Well, thank you 

everyone. I think as the Chairman mentioned at 

the beginning, everyone has the opportunity to 

comment on the topics that were covered today 

within the next two weeks. You can do that 

through our website. I believe there's a break 

now between this and the next panel. Thanks 

everyone. It convenes at 11:15.

(Off the record.)

MS. KIM: Okay. We'll now start the 

second session of today's roundtable, which is 

the regulatory treatment of forward contracts 

with embedded volumetric optionality. My name 

is Carlene Kim, Deputy General Counsel in the 

Office of General Council. And I'm joined on the 

panel today by my colleague and OGC David Aron, 

and my colleague in the division of market 

oversight, J.P. Rothenberg.

Any views that we may express today are 

solely owned, not those of any division or office 

of the CFTC or any Commissioner or the Commission. 

In the month leading up to and following the 

adoption of the seven part test, the staff met and 
discussed with market participants about the 

various interpretive and implementation issues 

that they face when transacting and certain 

contracts with embedded volumetric optionality.

The purpose of today's session is to 

build on that dialogue so that we can consider the 

relevant issues in a meaningful and thoughtful 

way. To set the background for the discussion, 

David will provide a broad overview and then we'll 

go around the room and introduce the guests; 

David.

MR. ARON: Thanks, Carlene. I just 

want to give a little background on how we got 

where we are today. So in 2012, the Commission 

and the SEC jointly adopted the final swap 

definition. The adopting release reaffirmed 

that, "Commodity options are swaps under the 

statutory swap definition."

But it also provided an interpretation 

that a contract with embedded volumetric 

optionality satisfies the forward exclusion. If 

it satisfies each prong of the seven part test, 

and it's stated that if it fails the test, it still 

might be a forward under a facts and circumstances 
analysis.

In the adopting release, the Commission 

solicited comment on the seven part test. Though 

some commenters supported the test, and or some 

of its elements, many suggested changes. Market 

participants raised questions regarding how to 

categorize contracts with embedded volumetric 

optionality and how to apply the adopting 

release -- the adopting releases guidance 

regarding the test.

There were many questions on the 

seventh prong in particular. Today we want to 

hear your current views and concerns on these 

topics to assist us in determining the latest 

state of play of these issues and how best to 

address them.

In this regard, we note that the 

comments received in response to the adopting 

release were received after the trade option 

exemption, but before DMO issued letter 13-08, 

providing further relief. So we'd like to hear 

the extent to which that addressed industry 

concerns.

And now we'd like to turn to the 
panelists for you to read your opening statements 

and then after that we've got some questions and 

we can have a little back and forth and if there's 

more time we could -- you could just address 

whatever you want to. So let's start over here 

with Jim.

MR. ALLISON: Thank you David and 

Carlene. I'm Jim Allison with Conoco Phillips. 

I'm appearing today on behalf of the Natural Gas 

Supply Association and I've been actively 

involved in this issue since the beginning.

The industry, as David noted, remarked 

on concerns about the seven part test as soon as 

we saw it. And we were among those who filed 

comments on it. I will say that the problems we 

noted in our comments as potential problems, we 

now know to be real problems. So it's no longer 

a hypothetical.

The first one I would highlight is the 

problem with parts four and five of the test. A 

strict reading and language in four and five works 

for calls but does not work for puts. There is 

nothing in the rule that explicitly says that puts 

are excluded and there are other aspects of the 
rule that appear to imply puts. So we have taken 

the view that it is a drafting error, not a policy 

decision.

If it is a policy decision then I think 

it would need to have substantially more backing 

than there is. Assuming it's a drafting issue, 

there is some language that we can provide that 

I think would probably fix it. As with other 

things, first choice would be to go back and redo 

the rule. Assuming that is not practical in a 

time frame that's important to us because this is 

a real problem right now, so we need a solution 

soon.

Interpretive guidance is probably 

something that would be very helpful but that 

assumes the interpretive guidance is actually 

definitive and reliable. Guidance that we can't 

rely upon is not actually useful.

So the -- the fix for puts would need 

to recognize that each party intends to satisfy 

its delivery obligations if the option is 

exercised and the respective delivery 

obligations are consistent with the character of 

the option as a put or a call. The problem with 
parts four and five as I now stands again, is that 

it works for calls but not for puts.

More significantly, of course, as David 

indicated is the problems with part seven of the 

test. Within the industry we don't see how part 

seven has any bearing on the statutory test for 

excluding a contract from the definition of swap. 

So again, in an ideal world, part seven simply 

would not exist.

In the real world however, it does 

exist. It creates real, not merely hypothetical 

problems. And we need definitive reliable 

solutions. And again, first choice would be to 

have a new rule, second choice is reliable 

interpretive guidance. And it needs to clarify 

what's going on and how we get these problems out.

Again, we have language to propose. I 

don't know that everybody in the industry agrees 

that the language is sufficient because again, 

first choice is a new rule. But I think the 

language would at least be helpful. And I'll 

talk about that more in a little bit. Let me talk 

a bit more specifically about the problems that 

we're actually seeing in reality.
There's disagreement about how to apply 

the test. The disagreement includes 

disagreements with smaller companies and you 

might expect that because you might expect 

smaller companies to have been less diligent in 

following the evolution of Dodd-Frank and the 

legislative and regulatory framework.

But we also see disagreements with the 

largest most sophisticated counter parties. So 

the disagreement, the confusion, is not limited 

to merely those companies who were not following 

it as diligently. This is a deep seated 

disagreement.

We do, in fact, at the moment have what 

might be regarded as a work around. We have 

agreed to disagree. With the ramification that 

one party may report the transaction on form TO 

and the other party not report the transaction on

form TO because the two parties have taken 

different interpretations of the status of the 

contract.

If you're happy with that inconsistent 

approach, you might regard that as a work around 

that will survive. I will note, however, that 
once we get to a position limit world, if trade 

options are in scope for position limits, that 

agree to disagree approach no longer works at all.

And there is a greater concern. In 

some requests for proposal, where the requested 

contract includes volumetric optionality, we 

have seen the requesting party ask of 

respondents, whether the respondent views the 

contract as a trade option, and if so, whether the 

respondent will take on the reporting obligation.

When a respondent sees that, a 

respondent does not know how saying yes, we think 

this is a trade option will affect the probability 

of success on that RFP. A company that takes a 

conservative view of these contracts might have 

some concern that that conservative view puts it 

at a competitive disadvantage versus respondents 

that take a more aggressive view.

Now I do not mean to cast aspersions on 

anybody in the industry. I do not know how other 

companies are interpreting the provision when 

they are responding to these requests. But any 

respondent looking at the RFP, seen that

question, has to wonder, has to be concerned, how 
the answer will affect the probability of 

winning. And that concern is a burden that no 

company should have to bear in dealing with 

regulations.

The language that I would propose in 

interpretive guidance on addressing the problem 

would have, I think, three elements to it. 

First, that the optionality -- well, and again, 

this is assuming that parts one through six have 

been satisfied and that assumes in turn that parts 

four and five have been corrected.

But assuming all of that, the 

optionality of whether a put or a call exists to 

meet the commercial production consumption or 

merchandising, which is to say the entire value 

chain, requirements of the option owners 

business, where those requirements can 

reasonably be affected by supply or demand 

conditions, regardless of whether the option 

owners arrange for multiple alternatives to 

address these requirements, and including cases 

where business judgments exercised in selecting 

among alternatives where the value is driven 

primarily by external factors.
The concern being that it is quite 

rational for a company to arrange multiple ways 

to address problems. Depending on the nature of 

the problem, you may need a different supplier or 

a different delivery pass to address the needs.

And come the day the problem arises, you 

need to make a rational choice among the 

alternatives you've created. And the prudent 

policy of creating multiple alternatives and of 

choosing rationally among them, ought not to, in 

any way, disqualify a physical contract from 

being treated as physical contract. And let me 

stop there. I could continue much longer, as you 

know, David. But let me give my co-panelists a 

chance to talk.

MR. JESKE: Hello, I'm Jerry Jeske, 

Chief Compliance Counsel from Mercuria. Many of 

the comments Jim just stated we certainly concur 

with. But to -- to try to expedite matters abed 

here, focusing on a few things that are 

particularly problematic. Prong seven of the 

seven part test, the language factors outside of 

the control of the parties I think is incredibly 

ambiguous and really creates confusion in the 
industry.

Jim also alluded to the agreement to 

disagree. I believe that's the genesis of the 

problem. That language needs to either be 

clarified or otherwise amended. I would also 

concur that the rule itself could -- could use a 

revamp. Another practical consideration that 

we're hopeful the Commission might take under 

advisement and -- and actually look at more deeply 

because it seems like this concept of gross 

notional applied to trade options is very 

misplaced.

I'll use the example of the heat rate 

option. There's the form TO that is required to 

be submitted to the Commission and then there's 

the one billion gross notional email that must be 

sent, or receive the punitive part 45 reporting. 

So folks want to be diligent about how they 

calculate but it's a bit of an impossibility when 

it comes to heat rate options.

Some folks might not be familiar with 

them, but a simple analysis, the numerator of the 

power of price times the mega watt hours, divided 

by the gas price creates a grossly overstated 
number that should not be included in the 

analysis. Folks understand what a heat rate 

option is basically trying to determine the power 

of price versus the power of gas. I'm sorry, the 

price of gas. But when you introduce the concept 

of quantity into that equation, you get a skewed 

result.

So what are you left with to decide as 

a conservative party to report, but an overstated 

gross notional number. So if there's consistent 

overstating on the part of the folks that are 

filling out form TO and submitting it, I question 

what value is that data to the Commission or to 

anybody.

Moreover, you have that -- this 

inconsistency existing throughout the industry 

and really a problem, I think, when it comes to, 

you know, the concept of agreeing to disagree. 

You're going to have parties who just won't 

calculate it the same.

Jim also touched on position limits. 

We certainly hope that trade options are exempt 

from positional limits. That would be the 

logical smart thing to do because it's an 
impossibility to bucket trade options together 

with swaps, together with futures, and come out 

with something that is manageable.

Last, I would say that we, you know, 

we're hopeful that the Commission does pay 

attention to this in a real time fashion, also as 

Jim has mentioned. And I'll turn it over to Todd.

MR. KEMP: Thank you. Todd Kemp with 

the National Grain and Feed Association. As I 

mentioned earlier, I remember firms include about 

a thousand companies nationwide. Grain 

elevators, feed manufacturers, processors; 

volumetric optionality is important to our 

industry in the context of cash forward 

contracting. I don't have a prepared statement 

for you but I'll look forward to participating in

the Q and A with some more detail.

MR. JOSEPHSON: My name is Ryan 

Josephson and I work for the Bonneville Power 

Administration, which is a federal powered 

marketing agency within the U.S. Department of 

Energy, created by Congress in 1937 to basically 

market power at cost from federally owned 

facilities to about 142 not for profit electric 
utilities.

I, too, haven't really prepared many 

remarks. Others just say that when Dodd-Frank 

was being sort of run its course, we had focused 

primarily on the swaps part of the legislation and 

really didn't pay due course to options and once 

we started looking into it we realized we had a 

slew of contracts that had immense volumetric 

optionality.

And given our statutory nature and our 

requirements, we realize that we probably should 

have paid a little more attention to the 

rulemaking around that and probably spend 99 

percent of the time in providing guidance to our 

trade floor, mostly on options and volumetric 

optionality.

Facts and circumstance, you know, 

generally causes us to air on the side of caution 

and when in doubt, look at things as a trade 

option, versus using the forward contract 

exclusion for a particular transaction. So to 

the extent trade options become part of position 

limits, potentially airing on the side of 

caution, may ultimately cause us and entities we 
do business with more issues than they currently 

do.

MR. PERRY: Thank you for the 

opportunity to meet today. My name is Eric 

Perry. I'm with the Scoular Company in Overland 

Park, Kansas. We are a cash commodity merchant 

in the agricultural space. And while this 

probably does not touch us to the extent our 

brother in the energy field -- does in the energy 

field.

As Todd pointed out, it does impact our 

forward cash contracting that we do. We -- we 

lean towards airing on the side of the cash 

exclusion in those contracts. So if we are going 

to evaluate them as trade options, we generally 

can satisfy all seven parts of the seven part 

test. But I would echo Jerry's points that the 

ambiguity in prong seven could leave some -- could 

be left open to interpretation.

And relative to position limit, that's 

probably where our bigger concern is in that we 

do view those -- those cash contracts with 

volumetric optionality under the cash exclusion. 

If trade options get rolled up into position 
limits, we will have to figure out how to isolate 

that, report that with position limits.

And that's not actually a position that 

we have. We deal with those positions as they 

come up and roll into our derivatives book as a 

long or short futures positions. But will -- it 

will be a change of course for us to have to view 

those in respect of the position limit roll up.

MR. PERLMAN: Good morning. My name 

is Dave Perlman. I'm here today on behalf of the 

Coalition of Physical Energy Companies, as well 

as, a number of other physical energy end-users. 

My clients are -- I'm from the law firm of 

Bracewell and Giuliani, and my clients are 

generally hedgers.

They are a great variety of energy 

companies from retail marketers to large 

integrated oil companies to EMP companies to 

electric generators. And while they have a lot 

of variety of business models, there's one thing 

that they can all agree on, they can interpret the 

seven part test in a way that they can 

consistently understand it.

And the -- as Jim mentioned earlier, and 
I'd like to note my agreement with Jim's proposals 

and comments, the mere fact that we run into a lot 

of issues and disagreements on whether a 

transaction is a trade option, among people 

addressing these issues in good faith, I think 

is -- is very real world evidence of, as Jim 

indicated, the concerns that we thought were out 

there have manifested themselves, because when we 

had the issue, leading up to the no action letter 

where we were all thinking about what are we going 

to do when we have to report this, we tried as an 

industry -- energy industry to sort of coalesce 

around different ways we could deal with it. And 

the no action letter put us into a position where 

we could agree to disagree.

Had we not had that situation, I think 

we would have had a much more fractious set of 

issues that we would have to deal with. Now 

whether that's a meaningful way to deal with 

things, where you have form TO where some people 

include it, some people don't, is a good -- good 

outcome. I'll leave that for you to decide.

But the bottom line is that we really 

can't meaningfully operationalize, this is my 
word, the seventh prong. We can't make it work 

in a way that we can make clear to our clients. 

And in my clients' case, we have a lot of clients 

who are not really sophisticated in the CFTC 

world, they're busy doing what they do in their 

physical business and they're very good at it.

So we've tried to get things for them 

that are useful in sort of a -- in a -- in a bite 

sized desk type of operationalized set of rules. 

And when it comes to the seventh prong, it's just 

not something we can do.

So what we would like to see happen, and 

again, since the acting Chairman is here, I'm 

going to be redundant and repeat some of the 

things that Jim said, I'd like to see you act in 

a prompt fashion, maybe with a long term view of 

fixing this -- you have a record, that you have 

comments filed, as David mentioned, you have 

other ways to deal with it in a longer term way. 

But we need some relief in the short term.

And while we would prefer to have the 

whole thing revamped or the seventh prong 

repealed, that would sort of the perfect outcome, 

in the meantime, we think and would hope, that we 
could get some clarification around what the 

seventh prong means. And if you'll indulge me, 

I'm going to sort of paraphrase what Jim said.

Because the seventh prong, as we 

understand it, is an attempt to say that the 

parties are engaged in something that is in 

conjunction with their business. They are 

actually undertaking a supply need or a 

merchandising need in coordination with their 

business and they've put the optionality in their 

contract so they can take action in the event of 

circumstances in a timely way that they have 

provided an opportunity to address.

It's not so they can monetize this and 

make a physical contract into a financial 

contract. That's not what we're talking about 

here. And if that's your concern, I'm hopeful 

that this language will help you. And 

it's -- where the optionality, inclusive for puts 

and calls, is intended to meet the commercial 

production consumption or merchandising 

requirements of the option (inaudible) business.

And so we're talking about physical 

commercial businesses, which can be reasonably 
affected by supply and demand, this sort of 

outside the control of the parties type idea. 

But that gives a little more granularity to what 

outside control means. And it's regardless of 

whether the option owner has arranged for 

multiple alternatives to address the 

requirements because one of the things that we had 

understood was if the option owner had multiple 

alternatives and they may be making a decision, 

let's just say, in this case, based upon the best 

price that that would be based upon economic 

factors, not on factors beyond their control.

And frankly, it is rational and common 

that parties will have multiple supply sources 

for reasons that have to do with the things Jim 

said, including reliability of supplier, certain 

other characteristics of the transaction that 

would make it more suited to their needs at that 

time, and of course, places important.

But if you need something for your 

business and you have something where price is all 

that matters, you might end up not getting supply. 

So you need to be redundant and careful to make 

sure that you get your commercial needs met.
And finally, and this is related, 

including cases where business judgment is 

exercised and choosing among those alternatives, 

including qualitative factors. As we're 

saying -- is I might have multiple alternatives. 

One is better than the other for my needs today, 

one is better for the -- than the other for my 

needs tomorrow. I'm making a prudent business 

decision, given the factors and alternatives I 

have before me.

The other two items that I think I'd 

like to address, given the limited time, is first 

the risk of ambiguity in our minds to around what 

optionality means. The Commission has precedent 

on the definition of an option and there was some 

language in the -- in the order about some 

Commission precedent and we think it may be 

useful. And we can follow up with comments on 

this to get a little more clarity and granularity 

on what optionality in these contracts means.

Is it -- doesn't need to be in the test 

of what the Commission has said an option is. So 

is it an option embedded in a foreign contract, 

as you've stated, or is it a foreign contract 
merely with different quantity opportunities in 

it? And we think maybe the former is the right 

answer.

And second, the position limits issue 

is a real material and really, really conceivably 

problematic issue. We are in the business, 

again, of meeting our physical needs of our 

businesses and we are undertaking something that 

is, in my mind, very hard.

If you look at the definition of a bona 

fide hedge that the Commission has proposed in a 

position limits rule to meet the test of a bona 

fide hedge. It isn't hedging a cash contract 

that has price risk. It is the cash contract.

You could maybe hedge your trade 

option, but your trade option is not something 

that you speculate in, it's not the sort of thing 

that has price discovery impacts, it's not the 

sort of thing that can be made sensibly or easily, 

as Jerry was saying, into futures equivalent. So 

we're hopeful that you'll understand and when you 

get to that aspect of things, not included in the 

position limits.

So as Jim also indicated, we'd be happy 
to suggest language to you in the comment period 

subsequent to this conference and be happy to 

answer any questions that you have.

MR. HUGHES: Good morning. My name is 

Paul Hughes. I'm the Risk Control Manager for 

Southern Company and I'm here on behalf of EEI, 

and ya'll know EEI is the investor -- represents 

all of the investor end utilities in the U.S.

I wanted to make -- maybe give a 

different perspective from the electric 

utilities side. But you know, generally fuel 

diversity is a very important component of 

electric reliability. And at Southern, we've 

developed a diverse portfolio of generation 

resources.

To meet our customers' anticipated 

energy needs, we build generation resources 

ourselves and we also purchase generation 

capacity from third parties. When the time comes 

to employ this generation, the industry uses 

complex dispatch models to analysis a combination 

of operational, locational, and market factors to 

determine what the resource mix should be. And 

the goal is for our customers to have both the 
lowest prices possible, while also maintaining 

reliability. So inherently, we build in a lot of 

redundancy to our processes.

Due to the current lack of -- of clarity 

in the rule, what we've found is that counter 

parties through a transaction may view the same 

transaction differently with some viewing it as 

a forward, some viewing it as a trade option, and 

some viewing it as a straight up plain vanilla 

swap.

And the willingness of the parties to 

agree and classify the transaction as a trade 

option is further complicated by the inclusion of 

the trade option and the new position limits rule 

is upcoming.

And now at Southern Company we have gone 

to great lengths to comply with Dodd-Frank. 

We've even developed software to help us evaluate 

all of these contracts and do they pass all of the 

factors of the various tests. And the result of 

that process and taking all of these contracts 

through those tests is we think there is a 

conflict between Section 1a(47) of the Commodity 

Exchange Act and the Seventh Factor of the 
Volumetric Optionality Test.

And the Dodd-Frank Act states that the 

term swap does not include any sale of a non 

financial commodity or security for deferred 

shipment or delivery, so long as the transaction 

is intended to be physically settled.

However, the application of the seventh 

factor, by Southern Company, and we readily admit 

we take a very conservative view of this, has 

resulted in the inclusion of several contracts 

that can really only be settled one way 

physically, yet in spirit of the rules and the 

languages there, we really think that perhaps 

that's not how they should be -- they -- not 

shall -- how they should be graded.

So accordingly, there's a conflict 

between the results that we're getting from the 

seventh factor test and what Congress intended. 

This may be due to the fact that the seventh factor 

has a misplaced focus on the option exercise. 

Because at first glance, the concept of excluding 

optionality based on primarily physical factors, 

outside of our control, seems reasonable, 

particularly when considering the impact weather 
has on demand.

However, this is problematic for the 

electric industry as it oversimplifies industry 

practice. Because the dispatch models take into 

account a multitude of factors when determining 

the resource utilization, attempting to 

determine the primary cause of exercise at some 

point in the future is impossible, even if it were 

a factor that is under our control. We just don't 

know at the time that we have to make that 

determination.

We think there's several solutions 

available to the Commission and we think simply, 

you know, one, remove or replace the seventh 

factor is one way. The other part -- the other 

way may be to change the focus of the seventh 

factor from the exercise of the option to the 

commercial intent of the agreement.

I would echo the same sentiments I think 

we've heard from Jim and David and others about 

some -- perhaps some -- some ways we could tweak 

that language to recognize that kind of physical 

operational intent that does exist and does 

not -- you know, we have -- we have activity that 
does not respond to price signals.

You know, when you value an option, and 

typically you value an option you look and say 

well you're going to assume based on the economic 

signals that option is always going to be 

exercised. Well that's not the case in our

industry. We have physical constraints that may 

prevent us from exercising that option.

We can't simply take one element and 

divide it and say well today it's an economics, 

tomorrow it's operational, the next day it's 

locational. For us, all of those components are 

inextricably linked. We can't just pull them 

apart.

And that's how I think what we're 

dealing with in trying to make determinations and 

that's, I think, what creates problems in the 

ambiguity between our commercial counterparties 

and leads to some of these disagreements may be 

a strong word, but longer conversations. I would 

say it's slowed down the commercial process a bit.

But that being said, I think there are 

several venues that the Commission could take, 

whether it's a change in the rule, whether it's 
something like the OGC did on their infamous 

however clause last year. I think there are 

several things -- several ways to get there and 

we welcome really any of those. So I appreciate 

the opportunity to come and talk and discuss this.

MR. NUELLE: Good morning. My name is 

Tom Nuelle. I'm the Chief Compliance Officer for 

BP's marketing and trading businesses in North 

America. And as such, I'm also the Chief 

Compliance Officer for BP Energy Company, a 

provisionary registered swap dealer.

I don't have any prepared statements, 

but I do echo what my co-panelists have said. We 

do think that the seventh prong on the test needs 

to be redone so it is very clear. We have seen 

instances where we do disagree with parties on 

whether things are generated options or not and 

a lot of times there is an agree to disagree.

For -- and we're at kind of a unique 

perspective than I think others on the panel, 

being a swap dealer. We have a higher obligation 

under real time reporting that we have to get 

these reported to the SDRs within two hours now. 

And that can -- if it's vague, it generally means 
that the marketers are having to come to 

compliance, to legal, to get definitions on -- a 

confirmation on whether things are trade options 

or not.

We can't necessarily give them just 

fool proof guidance where they can go out and run 

their business. If it would give them very 

little and ask them to come back -- that takes time 

and it takes efforts. And then the other part 

four is swap dealers. We need to be able to 

isolate these deals easily in our system to be 

able to efficiently report them to the SDR. 

Right now that's a very manual process as you can 

imagine from having to identify these -- these 

options as deals are getting done.

And since there are no standard format 

to put these in, a lot of them are -- are submitted 

manually to the SDRs, which again, takes time from 

the commercial staff, mid office staff, all of the 

way back to our confirmation staff to make sure 

that that happens and that is quite burdensome.

On position limits, I would agree that 

they do -- they shouldn't be included in the 

position limits. These aren't -- I think it was 
David who said these aren't instruments that can 

really be traded in and out of and a lot of times 

we are doing these things for -- as a service to 

our customers who are looking for different ways 

to get molecules, who run their business on -- on 

stress days.

And so if they are included in a 

position limits, that would cause them to be 

physical contracts, which if the conditional 

limit does pan out in the new rules, we may not 

be able to or a company may not be able to take 

advantage of that if that -- the only thing they 

have sitting on the physical -- on delivery 

contracts is CTOs, which you can't just go and get 

out of on an easy -- on an easy basis. There's 

no standing market for that.

So given that, we would prefer that they 

not be included in the position -- position 

limits. And as I said, we can focus the position 

limit activity on the futures and the swaps and 

the -- over the counter swaps. Thank you.

MR. TURBEVILLE: Good morning. My 

name is Wally Turbeville. I'm from Demos, which 

is a -- a public policy think tank and advocacy 
organization. And as such, I'm -- I'll have 

different sets of interests than anybody I see 

around on the table. And I understand your 

interests, I do.

I understand that you don't want 

to -- you want to do -- you want to burden your 

business as little as possible and I -- I really 

appreciate that. But our interests -- what 

we're -- we're -- we're focused on is the public's 

interest. And the public's interest is 

expressed in the Dodd-Frank Act and in the notion 

of transparency.

I don't normally do this but before I 

was in the business such as it is of thinking and 

writing about these kinds of issues, I spent well 

over a decade at a -- in the energy group of a major 

investment bank and then later for another seven 

years, ran a derivatives -- an energy derivatives 

risk business to manage that risk.

So I -- I -- I kind of think of these 

things maybe a little bit differently. And I 

think part of the -- part of the problem is almost 

a fundamental conceptual problem with the 

discourse. When you say we can't get out of these 
things, what are these things? I think of these 

things as if -- if there's something -- if there's 

a risk package inside a contract that could be 

hedged in the marketplace, not detached and 

marketed, which I -- I -- I -- who -- who detaches 

and markets any -- any derivative. You 

don't -- you don't sell a derivative, you cover 

it.

So I think if -- I think fundamentally, 

if something can be detached and hedged in the 

marketplace, it is a derivative. I think that if 

there's -- there's a sophisticated party on the 

other side of the transaction, they view it as a 

derivative, they'll put it in their risk book as 

a derivative, they'll -- they'll -- they'll 

measure it as a derivative.

So -- so the -- the -- the 

question -- the going in question of optionality 

is one where is this the kind of thing that could 

be sui generous hedged and -- and -- and addressed 

in the marketplace.

I understand that these things aren't 

intended on your part, for most of the people who 

have spoken so far, to monetize or to speculate 
but then neither is a conventional bilateral swap 

with an end-user. It's not -- I don't think 

it's -- I don't think it's a question of whether 

the -- the thing is intended to -- to -- to be 

monetized.

If there's -- if -- if it addresses a 

legitimate risk in your business, that might have 

some pertinence with regard to -- to position 

limits. I understand that, too. But -- but that 

doesn't change the fact 

that -- that -- that -- that it just can't be 

ignored and that this is indeed an option.

Now, also having had the experiences 

I've had, I understand further that when some 

folks in the marketplace who are very 

sophisticated do a contract like this with an 

embedded option, the pricing of that option is 

something to feast on because -- because the fact 

of the matter is, that the complexity associated 

with embedding an option in a physical contract 

is something that is the opposite of 

transparency.

It's -- it's -- it's the ability to 

obscure because -- because the quantitative 
analytics associated with it can be -- can 

be -- can create a situation where -- where 

pricing is -- is -- is -- is very difficult to 

understand.

So in one sense, I think there's a value 

to the -- to the -- to the market in terms of 

actually getting transparency and getting 

reporting and -- and -- and -- and seeing what this 

option is -- is -- is really worth. I think 

that -- I think there's -- I think that's -- that's 

actually an advantage that -- that -- that is 

ignored because I understand people want to do 

things the way they do things and have done things 

in the past.

So that's where I'm coming from and 

where -- where -- where I'm going to be coming from 

in the discussion. I do want to go back to the 

heat rate question, the heat rate option 

question. And -- yes, sir; hi.

The heat rate option question is one 

that seems fairly straight forward. The heat 

rate is -- the heat rate is nothing but an 

evaluation of the -- of -- of the conversion from 

gas to electricity. And there is a -- there's a 
volumetric value associated with that.

But that is no -- to me it's no different 

from an option or a swap in terms of the -- in terms 

of -- of -- of -- of -- of it's -- of its notional 

value, as long as you -- you're valuing -- the 

value you put in is the right value to start with 

and the quantity is the right quantity. So maybe 

that can be discussed. Thank you.

MR. CERRIA: Hello; okay. I'm Chuck 

Cerria from Hess Corporation. I've been 

involved in -- in trading and physical 

commodities since, I believe, October of 1998, 

from both the perspective of the -- the provision 

of the commodity to the -- to the commercial and 

industrial users who potentially end up to people 

such as this building and the lights on in this 

room now.

So I've also been exposed to the trading 

side of things, the structured products and 

everything else. And by the way, just 

to -- housekeeping, I'm here on behalf of 

Commodity Markets Council and what I'm saying are 

my own thoughts and not to be attributed to any 

other -- anybody else; okay. So I just want to 
get that out.

But getting back to my opening 

comments, I don't know if they're prepared or not. 

I have kind of notes all over the place here. But 

I agree with all of the points. I'm not sure I 

understand a lot of what Wally is saying so I 

can't -- I don't know if I agree with Wally but 

I know I agree with -- with my other panelists to 

the extent that they've gotten into the weeds.

I -- I agree with those and we've seen 

some language and we're -- we're willing to work 

with -- with you, David and Carlene, to you know, 

to maybe improve upon the seventh prong as at 

least in intermediate step. But if I could, I'd 

like to just ascend a little bit and maybe go 20, 

30,000 feet up and actually commend everybody and 

commend the Commission for being as vigilant as 

you have been in trying to distinguish a physical 

from a financial.

I -- the reason that I -- that I offered 

to join this panel is because I actually think 

that's the single most important topic in all of 

Dodd-Frank, okay. Because everything -- the 

waterfall just rushes after that determination is 
made. And so getting this correct, I think, is 

the single most important thing that we all can 

do and I appreciate the effort from -- from the 

Commission, and even Congress, okay, because as 

other panelists have said, you know, let's focus 

on the fact that Congress expressly excluded 

transactions that are intended to be physically 

settled at the time of the transaction. That's 

an express exclusion and I think we 

should -- that's got a lot of significance and we 

should never water down that significance; okay.

So correctly distinguishing between 

what's physically settled and what's financially 

settled or a financial instrument so to speak is 

absolutely critical to getting this whole thing 

right; okay. And just as -- again, maybe I'll go 

another 5,000 feet up and say that it's 

significant not only within the U.S., it's also 

significant worldwide within the G20. And Mark, 

I know that you've been outreaching a lot over the 

last few -- few months. Thank you for that.

But you know, the EU defines financial 

instrument, which is I think probably close to 

what we're calling a swap here, and thereby 
mandating clearing -- they include physically 

settled contracts that are traded electronically 

on a multilateral platform and that's -- that's 

different than what we're doing here.

These kinds of things have got to be 

ironed out and we have to have a clear division 

recognizing the value of a physically settled 

contract versus a financially settled or 

financial instrument. So this work is really 

important, okay.

Getting back to the provision of, in my 

case, energy, okay, or molecules. I mean 

they're -- they're -- they're -- we are providing 

an essential resource and commodity to society, 

okay. And I'm not going to get too dramatic or 

too -- too over the -- over the top here. But 

that's really what we're talking about.

Again, like the contract to supply, to 

power the lights that we're all enjoying now, 

okay. If we decide to switch off the lights 

because we're going to go on break or something, 

we've turned off the power. I mean that's the 

kind of volumetric variability, if you want to use 

the word variability instead of optionality, 
okay, that we're talking about when you deliver 

a commodity; okay.

And it's the same with oil and whatever 

the commodity is from an energy standpoint. I 

can't speak for grains or metals; okay. And so 

we've been doing this for decades with much 

success.

We, you know, we -- our commercial 

market participants, we've established the 

ability to do that and society actually 

appreciates that and these volumetric 

optionalities as they're called that are embedded 

into these contracts, developed as a consequence 

of the market trying to sharpen its efficiencies 

so that only the amount of molecules that need to 

be dispensed to satisfy demand are dispensed and 

no more is wasted. So there -- there's a lot of 

public policy behind efficiency and encouraging 

the market to continue to develop its efficient 

means; okay.

So getting back to what I said earlier, 

now -- and by the way, I think I've come down about 

20,000 feet, okay. So getting back to what I said 

earlier, we -- we don't please -- we -- we -- we 
can't allow ourselves to -- to be persuaded to 

think that these are speculative financial 

instruments. The -- we're talking about the 

basic commodity contracts here. And when you 

deliver a commodity, you're -- you're going to 

have variability and volume. That's just how it 

is.

And so I think I've talked for a while 

and I'm not going to talk anymore. The only thing 

I want -- I want to end with is, and David has said 

it and -- and a lot of people have said it, what 

we need is we need something that's workable in 

the moment when these transactions are executed 

at the time of the transaction, something that the 

parties all agree either is a forward contract 

exclusion or is a commodity trade option or is a 

swap.

And you know, getting back to 

transparency while I do agree with you on the 

value of transparency, when you -- when you sit 

back now and look at what do we have in the SDRs 

and what do we have in foreign TO reporting that 

we've all just gone through.

We have a lot of probably 
inconsistencies like everybody is seeing here and 

that devalues the reporting and the transparency 

and worst case is it actually leads us to a path 

of thinking we have reliable information when we 

really don't. So it's that false sense of 

security that always like nags at me; okay. And 

so I think I'll leave my opening comments here. 

Thank you.

MS. DONDNAVILLE: My name is Patty 

Dondnaville. I'm a partner at Reed Smith and I'm 

here at the request of the not for profit electric 

coalition, which is the coalition of rural 

electric cooperatives and municipals government 

owned utilities that are the quintessential, if 

you will, end-users in the marketplace.

Their job is to deliver power 24/7, 365, 

to their clients, their customers. They have, as 

Chuck and David said for years, distinguished 

very clearly between contracts where they intend 

to physically settle, which is 99 percent of what 

they do, and financial instruments that they use 

solely to hedge so they don't, as the professor 

was saying, speculatively trade.

They don't trade in metals or crude oil 
or financial commodities of any sort in a trading 

sense. They use natural gas, electricity, and 

other energy related commodities and commodity 

swaps to hedge their commercial risk of 

operations.

To comment on the volumetric 

optionality, I really need to go back to Chuck's 

30,000 feet. Because all of this generates from 

an interpretation that David Aron sited at the 

very beginning, which was the Commission's 

interpretation that the statute before it, 72,121 

of the Dodd-Frank Act required it to see all 

commodity options as swaps.

We're not in an exercise to determine 

whether things fit in one of three categories 

here. There are two categories. Is it a swap or 

is it not a swap? That's the question that all 

of my clients are asking me on a day to day basis. 

Because if it's a swap it has consequences. You 

have to report it within two business hours, 

within 48 business hours if you're end-user to 

end-user.

So swaps have consequences. If I 

respond to them with a series of interpretations, 
and they're not rules, they're interpretations of 

the CFTC. They're not joint rules with the SEC. 

Footnote 205 essentially says the CFTC takes no 

part in this section of the interpretations in the 

products definition release.

So there are interpretations out there 

and the energy industry, as Jim said, has 

requested since they were published that they be 

withdrawn.

My group has on file with the CFTC a 

request for reconsideration of that basic 

question. Are all commodity options, even if the 

parties intend to be physically settled, swaps? 

We think the answer is no and we've asked the CFTC 

to go back and reconsider that legal decision and 

we've not heard a response.

So, I think I agree with what Jim said, 

what David said, what Paul said. The energy 

industry is looking to the Commission. We're 

very appreciative of this dialogue. We've 

provided the CFTC with reams and reams of input 

on how these tests, these interpretations don't 

work in our industry, and we're asking the CFTC, 

first address the motion for reconsideration. 
Let us brief it. Let's talk about that 

conclusion.

Beyond that, let's treat the symptoms 

of the underlying problem with please withdraw 

the seven part test, the test that -- the 

interpretation that's out there with respect to 

physical commodity transactions. You asked 

seven questions, we answer. We would like, in 

most instances, for you to withdraw that, but if 

not, let us know what you don't understand about 

the comments that we've submitted about how they 

don't work in our industry.

Let's open the dialogues. Let's see if 

there is a way those interpretations can be fixed 

so that the CFTC doesn't see what I call option 

ghosts because when you're seeing those option 

ghosts in our 200 page contracts, you must be 

seeing swaps because otherwise we wouldn't be 

here.

And if you're seeing swaps, then those 

should be reported. But the reason you're having 

such problems with your swap reporting is because 

there is this tremendous disagreement as to 

what's a swap and what's not a swap. And people 
are not taking a conservative view or an 

aggressive view.

I have clients all along the range of 

that perimeter that are taking different views of 

the same transactions and then they're trying to, 

in some cases, take a conservative view and slam 

those puppies in to the very narrow descriptive 

data elements for swap reporting. And they're 

doing that in different ways.

We talked about not having trade 

options be under position limits. Well that's 

because they're not swaps. And what position 

limits are intended to do is test financially 

settled contracts, not physically settled 

contracts.

So as I say, it all goes back to the 

ultimate question. How can we engage with the 

Commission in a constructive dialogue about 

changing the underlying interpretation of 1a(47) 

and if not, how can we treat each and every one 

of the symptoms where that will continue to pop 

up in your rulemakings, in the Federal Reserve's 

rulemakings, once they come forward with revised 

rules on margin and capital? Because these 
things are going to come up time and again unless 

we fix the underlying question of what's a swap 

and what's not a swap.

MS. BERGLES: Susan Bergles. I 

represent energy utility clients and today I am 

here on behalf of the American Gas Association and 

I'd just like to start out. I'll be brief, going 

last, but just thank you to Chairman and staff for 

holding this very important conference on this 

very important topic. I'm looking forward to 

having more in depth discussions along the lines 

of what folks have been talking about already 

today.

Briefly, the American Gas Association 

members are regulated energy utilities that 

deliver natural gas to millions of residential, 

commercial, industrial customers throughout the 

United States. These entities stand ready to 

meet their customers gas needs at rates, terms, 

and conditions that are subject to state 

regulatory authorities.

Again, these entities are regulated 

entities. They're used to being regulated. 

They understand regulation. They understand 
compliance. What we have been talking about 

around the table here is entities need to have 

more clarity to understand what -- what is a swap 

and what they should be complying with.

Part of how gas utilities meet their 

obligations to provide gas to their customers is 

they develop seasonal plans, as we discussed 

before, including a portfolio of various supply 

sources, storage, and transportation. Included 

in these are the non financial physical commodity 

contracts. Because meeting customer needs is 

impacted by weather, which cannot be accurately 

predicted or forecast, a certain amount of 

planning goes into entering into contracts with 

volumetric optionality.

This is done to cover your changes in 

your customer need and demand fluctuations. It 

is also the intent when we enter into these 

contracts that what you're getting is the ability 

to confirm physical supply. The intent is that 

the product is going to show up upon request.

So physical delivery is the underlying 

intent and these transactions are viewed by the 

gas utilities. That's just common and necessary 
tools as part of their ability to meet the 

reliable and cost efficient needs of their 

customers.

AGA does not believe that Congress or 

the Commission intended to include peeking or 

swaying contracts under the Dodd-Frank 

regulations as swaps. We believe that they 

should be excluded from the regulation as a swap, 

but under the seven factor test, as we have been 

discussing today, there remains regulatory 

uncertainty.

In order to alleviate that regulatory 

uncertainty, we propose CFTC Commission action to 

address the comments that have been filed in -- in 

the open docket, the further definition of swap, 

comments filed October 12, 2012. And included in 

that, I would echo some of the discussion that has 

happened -- that has gone on today, which is with 

respect to the seventh factor, the proper focus, 

we believe, and it's in AGA's comments as well, 

should be on -- on the -- whether or not the 

transaction satisfies the seventh factor at the 

time the transaction is entered into.

Have -- have there been compliance 
challenges? Yes. I'll be happy to discuss 

those further in detail according to your 

questions today, but others have already 

discussed there's been disagreement, there's 

been confusion in the marketplace.

People are reporting on form TO 

probably different. Some are classifying things 

as a trade option. Some folks may be considering 

them as an exempt forward. That's why, again, we 

believe it's critical to have regulatory 

certainty.

Briefly, have there been -- one of AGA's 

concerns has been impacts on the physical natural 

gas marketplace. There has been impact on market 

liquidity, innovation. AGA members are seeing a 

decrease in the kinds of commercial offerings 

counterparties are willing to make. A decrease 

in the number of commercial counterparties 

willing to enter into these flexible 

transactions, which gas utilities rely on to 

serve the needs of their customers.

Again, this is impacting the robust 

participation and the innovation that the 

industry has had for the last 20 years. That's 
also resulted in billions of dollars of savings 

to customers.

So ultimately, you know, the ultimate 

impact, if you need any more reason to -- to do 

something about this, is definitely that the 

impact is ultimately passed through to customers. 

Gas utilities, any -- increase costs in 

procurement of gas supplies are passed through to 

their customers at cost. As a result, you know, 

increased gas costs will ultimately lead to 

higher natural gas prices paid by the American 

Energy customers.

So again, we believe it's critically 

important for the Commission to provide 

clarification in the form of a final rule based 

on the comments and the clarifications requested 

in the docket. We believe that part of that 

clarification should include the focus on the 

intent of the -- the transaction when the 

transaction is entered into.

And briefly, I will just say the AGA did 

file comments in February of this year on position 

limits and consistent with folks around this 

table has taken a position that trade options 
should not be subject to position limits. Thank 

you for the opportunity to speak at this 

roundtable.

MR. WETJEN: Susan, can I ask you a 

question --

MS. BERGLES: Sure.

MR. WETJEN: -- Quick question. So 

help me understand a little bit better if you 

could, the practical effect of when you have two 

parties that are considering entering into some 

kind of an agreement but they don't agree as to 

what kind of a contract it is, whether it's a 

forward or a trade option. So other than because 

of the disagreement, one party deciding they 

might not want to enter it in -- enter into the 

contract, what are some other things we should be 

mindful of or what other kind of problems does 

that create?

MS. BERGLES: Well, I think that this 

first round of reporting on form TO happened and 

people were looking at transactions that they had 

already entered into. So I think folks were more 

concerned about reporting for their own self and 

their own regulatory compliance so they were 
making the best decisions they can. And probably 

out of an abundance of caution due to maybe a 

reluctance to have it fall within the seven factor 

test, they're going to report maybe the 

transaction as a trade option.

Going forward, I know some of my clients 

have not negotiated some of these transactions 

yet that will occur in the summer. They have 

already informed me that two of the main entities 

that they have done transactions for flex -- with 

flexible delivery terms in the past have decided 

to exit the natural gas business.

So that -- that -- that's going to be 

an impact. So those -- a lot of the new 

discussions, at least to my knowledge, have not 

taken place. I don't know if other people around 

the table --

MR. WETJEN: That probably -- because 

I think Paul had mentioned that a lot of times 

you're having longer conversations. It may be 

end up being resolved. So at the beginning of the 

conversation maybe there's confusion, but at the 

end of it perhaps there's not -- get a sense of 

that and whether there might be --
MR. HUGHES: Sure.

MR. WETJEN: -- other practical 

problems being created by all of this.

MR. HUGHES: Sure. I think -- I 

think -- and I think Susan alluded to it. But it 

does -- I think it does extend the commercial 

transaction time because there is this discussion 

of wait, is this a trade option or not a trade 

option, is it excluded for it, is it not.

And those parties, I think the way the 

rules are set up legitimately can have a different 

view of that because I think we -- I don't know 

if we mentioned it or not, if anybody here 

mentioned it or not, but there's kind of this 

underlying question. Can I rely on my 

counterparties rep on their representation?

So if they say I'm only going to use this 

commodity for something outside of my control, 

okay, well can I -- can I honestly accept that rep 

and move on? I have to be very careful before I 

answer that. I'm -- I'm -- I'm not an attorney.

I'm just trying to implement the rules. 

But I can tell you my attorneys come back and say 

well wait a minute, well we, in essence, kind of 
turning over our compliance to a counterparty 

because what if there is some type of contract and 

insert whatever commodity you want to but there 

is flexible -- flexible delivery options.

And let's say you -- they can take from, 

I'm just going to say, zero to 500 (inaudible) 

megawatts, whatever you want to put in there and 

the first two -- say it's a 10 year agreement, long 

term agreement.

So those first two days, they take lots 

and lots and lots of volume. Day three, day four, 

through the rest of the term, let's say they don't 

take anything else, am I now in an awkward 

situation where I go wait you told me this is only 

going to be for regulation reasons. I know it was 

really hot outside, but nobody ever called on 

this. And it puts me in a very awkward situation.

I think -- so I think you find 

reluctance on both parties. I don't -- I don't 

think it's, you know, it's just -- but I think 

we've kind of seen and heard that. And then I 

think there is kind of this adherent reluctance. 

I know we kind of agree to disagree. I think that 

was in this discussion or maybe the one before 
that agree to disagree is a work around. It 

doesn't feel good though; all right.

I mean so you agree to disagree but you 

know that, you know, for example I'm going to 

classify something as a trade option and the other 

party says no, that's not a trade option, well I'm 

going to include that in my form TO and that other 

party is going, hmm. So this is -- there's 

this -- this disagreement of contract now that's 

being reported on someone else's regulatory 

report.

If they come back, if somebody wants to 

look at that and the detail -- why is your -- why 

are you not there. And I think there is just a 

natural reluctance when parties can't agree to 

kind of absolve themselves of that and -- and it 

does -- it does slow down the commercial process.

MR. PERLMAN: Can I add to that? 

Because we have -- I have multiple clients who 

have dressed this all kinds of different ways. 

And it goes to some degree to what Patty said. 

They don't -- some of them are not sophisticated 

in this area. They're very sophisticated at 

their business and they've decided we don't want 
any swaps. We're not going to report anything. 

We don't want any swaps. That's our policy.

So they had contracts of volumetric 

optionality until this rule came out. Now they 

don't have them at all. They won't do them. So 

they're significant natural gas entities.

They do not do contracts of volumetric 

optionality. They can do much more logistically 

difficult transactions where they can enter into 

multiple individual contracts that have a 

quantity.

So instead of having a contract that had 

optionality in it, where it could be moved around, 

they have to instead enter into daily contracts 

or hourly contracts for quantities, which is much 

more burdensome but it gets to the same outcome. 

Maybe that's what you meant by a workaround.

The other thing that I mentioned was 

that when we came towards April of 2013 and we were 

looking at the need to report, it was obvious that 

the parties in the marketplace could -- were not 

going to be able to agree. And as Paul said, 

there's discomfort on the fact that we can't.

We've run into parties that want to put 
reps in agreements. This is one of the issues 

with reps, where all of the transactions that we 

will do, today, for the rest of time, will have 

the following characteristics. These are 

contracts we haven't even seen yet.

And we see a lot of people trying to put 

those reps in contracts, which is problematic 

because the lawyers work on the reps and then the 

business people do the trades and maybe there's 

a discontinuity between the trade that happens 18 

months later and the rep that was made. Who 

knows?

MS. DONDNAVILLE: And the operations 

people are the ones that actually exercise the 

option --

MR. PERLMAN: Exactly.

MS. DONDNAVILLE: -- at some point when 

it's below zero across most of the mid -- middle 

west.

MR. PERLMAN: Right. And let me just 

say --

MS. DONDNAVILLE: So from -- go ahead.

MR. PERLMAN: The final thing and I'll 

turn it over to you, Patty. Is that because of 
the way form TO works, where you can have 

individual reports without -- without consensus, 

I'm sorry, you end up with a situation where 

people have no need to agree.

And the freedom to decide what you think 

is right, in good faith that I'm assuming, and 

report whatever you want, is -- is really a way 

that the regulatory requirements of the 

Commission kind of fall by the wayside because 

nobody ever has to deal with it. We will if we 

have to deal with position limits.

People have -- I've gotten more 

questions than you would suspect where 

they -- people say what is the Commission's 

remedial authority and what kind of penalty can 

I have if I mischaracterize something as a trade 

option. That shouldn't be. Or the other way 

around because people are concerned that they're 

making a mistake in calling it a trade option.

And I tell them it's $140,000 and 

they -- they don't like that. I tell them that 

I think the Commission is at a reasonable place 

and the Commission is not going to penalize you 

and they say we -- we are conservative compliant 
entities. We want to do it right. Your judgment 

is appreciated, but that's not the real 

determinate, it's the Commission's decision.

So I think you can get a level of, I'll 

call it, false comfort from the fact that people 

have not had to agree and they've had these 

discussions and maybe parted ways at the end. 

But at the end of the day, from a regulatory 

perspective and a true compliance perspective, 

there's really no true consensus or understanding 

of what the Commission is expecting.

MR. TURBEVILLE: I think that if you go 

for -- from the other direction, clarity is really 

good and that's an important thing and I think 

that -- I think it's an unfortunate thing that 

these discussions are going on and -- and people 

are taking different views. That's not -- that's 

not good.

But the other way to look at this is they 

really are options. And they -- and it's you 

can't do anything about it. 

And -- and -- and -- and instead of -- when I 

read -- when I read the rules, it seemed to me that 

the Commission was trying very hard to be as 
accommodative as possible, but underlying all of 

that is that these things are really options.

And there's a complete -- we're not 

talking about the contract of delivery and the 

settlement of the delivery of the natural gas or 

electricity, we're talking about the option that 

is embedded in it. And you know, if you -- if you 

look at how, you know, Goldman Sachs, Morgan 

Stanley, J.P. Morgan, built their businesses 

around derivatives and physical, especially in 

businesses like electricity, which -- where the 

physical -- it's not -- it's not like a bushel of 

corn. The physical in electricity is energized 

electrons.

So there's -- there's -- there's no 

bright line distinguishing factor when it comes 

to what is a -- what is a swap or an option and 

what is a physical. It -- it -- it -- those blend 

into each other over time financially.

But the other way to -- my point being, 

the other way to address clarity is to actually 

make it very clear that we recognize that these 

things are -- are -- are -- are options, 

which -- which they really are and then proceed 
accordingly. And -- and -- and you know, 

if -- if -- if the fact is that somebody is doing 

options and they -- they need to report, okay, 

they need to report.

Somebody has made the decision, 

Congress, that -- that that's -- that that's 

overall good for everybody. And I do not believe 

that the lights are going to go out or natural gas 

is going to cease flowing if -- if the outcome is 

that these things are recognized as options when 

they can be actually hedges in the financial 

marketplace.

MS. DONDANVILLE: Can I come back 

though and point out that Congress didn't put in 

place in 2010 something that says options need to 

be reported. They put in place something that 

said swaps need to be reported. So again, this 

traces back to the question of whether if the 

parties intend physical settlement, which if 

there's one rep I think you would agree, David, 

and all -- all of you would agree, people are 

perfectly willing to put in their forward 

contracts. Whether or not -- is that they intend 

physical settlement. I've never gotten 
disagreement about that.

MR. TURBEVILLE: Physical -- physical 

settlement is a physical or physical settlement 

of the option?

MR. ALLISON: No, physical settlement 

of the option --

MS. DONDANVILLE: Physical 

settlement --

MR. ALLISON: -- is precisely the 

question.

MS. DONDANVILLE: -- physical 

settlement. As the rule says, physical 

settlement, not of the option, not a delivery of 

the option contract, but physical settlement of 

the delivery of the commodity.

SPEAKER: I understand that.

MS. DONDANVILLE: Okay. And there's 

nothing -- absolutely. We're not talking about 

the delivery of an option contract here. What 

we're -- what we're talking about is what needs 

to be reported and what doesn't need to be 

reported. And the CFTC is not putting in place 

options reporting. What this is about is swaps 

reporting.
And the disagreement as to what needs 

to be reported is that fundamental question. Am 

I entering into a swap? Because it has 

consequences if I am. Don't give me an answer 

that says there's a seven part test to figure out 

whether you have an option. That's not the 

question I asked, say my clients. My clients say 

is it a swap or not.

MR. ALLISON: So if I can pick up on 

that point, Patty, it -- there are some contracts 

that have variable volume where there is a 

legitimate question about whether it's an option. 

And that's on the second page of the questions 

that were circulated for this panel.

For the most part, Wally, however, the 

question is not whether there are options. These 

are options. They are structured as puts or 

calls. They have a premium associated with them. 

We invoice for the premium and we expect to get 

paid. There are provisions that describe how 

exercise -- these are options. That's not the 

question.

The question is are these options 

intended to be physically settled because it is 
that that takes it out of the definition of swap 

according to the statute. And everything we're 

talking about here, parts one through six of the 

seven part test, assuming you fix four and five, 

parts one through six speak to the question, do 

the parties intend for this to be physically 

settled.

Part seven, to my mind, doesn't even 

address that question and the question it does 

address it addresses with such ambiguity that we 

have all of this confusion. And Mark, I can 

assure you the agree to disagree is not a 

hypothetical. It's real.

And that means that there are contracts 

that we have reported on our form TO where our 

counter party has told us we don't think that is 

a trade option, we do not intend to report it, 

though I don't know what they actually did.

Because as Paul points out, once they 

know that we intend to report it, that may alter 

their decision about what they do. But I know 

that as we are preparing ours we said in our 

opinion this is a trade option because I cannot 

prove to myself that part seven is satisfied and 
I don't really care what rep you're going to give 

me because unless -- unless the contract is such 

or your regulator is such, your hands are 

completely tied.

We know you to be a business like 

counter party and we expect you to operate at a 

businesslike manner and that causes you to fail 

part seven. So you can give us a rep; we're not 

going to believe it.

MR. WETJEN: And the reason we're all 

here today is to solve problems and I just was 

reflecting on your response, Jim, thinking about 

what David said. And I thought you said that 

market participants are entering into a number of 

additional contracts in place of just doing a 

forward of volumetric optionalities. So the 

question is how practical of a solution is that?

Obviously it sounds like it's a little 

bit more difficult because you're entering into 

a bunch of contracts instead of one, but help us 

appreciate more just how cumbersome that is. In 

other words, if people are doing what they need 

to do, are still able to do what they need to do, 

perhaps differently and through additional 
transactions and what was done before. But is 

that something we -- to what degree do we need to 

think about that and --

MR. PERLMAN: The point is that there's 

a regulatory -- there's a regulatory ambiguity 

that we think if it is clarified would rectify the 

issue. And absent the clarification, if there's 

a business decision that's made, we don't want to 

be reporting anything, we don't want to engage in 

activities that are going to be CFTC 

jurisdictional. They can find ways, in this 

case, around it, but that is less efficient, it's 

less timely in able to act, it's difficult to do 

the overriding initial business deal that's the 

best economically effective business deal, and it 

relies -- it -- it -- it requires there to be a 

real time interaction that's more robust and has 

more documentation issues associated with it. 

Is it impossible to do? No, it's not. Is it a 

productive use of resources? No, it's not. 

Does it benefit society to have to go through 

that? My judgment is no.

I want to just say one thing in response 

to what Wally said because I used to be the Head 
of Legal for Lehman Brothers Commodity Business. 

They're -- they're not around anymore and I don't 

know if you heard about that. But -- and we did 

a lot of things on Wall Street where we priced 

options, we understood what we were doing, 

everything was directed at monetizing things. 

They were not -- they were physical businesses, 

but they were very much, at the end of the 

day -- they had a physical component but it was 

very financial in a lot of ways.

That is hugely different than Paul 

running a power plant to serve Patty's customers 

and having Patty's load guy call up and say to 

Paul, look, our -- we lost our peaker unit, we want 

to increase the dispatch on your power plant 

because we have the right to ask you for that 

because we're trying to keep the lights on at our 

customers' house.

That's what we're talking about here. 

We're not talking about Goldman Sachs doing some 

kind of financial engineering of an option 

product. We're talking about in the main, 

commercial parties, commercial entities, that 

are -- require optionality in their fundamental 
arrangements with their counter parties to meet 

their commercial needs.

So I don't quibble with what you're 

saying in certain circumstances, but I think that 

limited aspect of things -- if you look around the 

table, you see a lot of entities represented here 

who are just trying to do their commercial 

business and also be compliant with what the 

Commission requires.

MS. DONDNAVILLE: Think what an odd 

conversation that would be. My client would have 

to say to Paul, I want to call on your generation. 

Paul would have to say back is the sole reason or 

the primary reason or the principle reason you are 

exercising or not exercising the option your 

demand or am I the cheapest in your dispatch pile 

because you have choices as to which generation 

unit you ramp up. And if the answer is you're the 

cheapest, can -- does he have to say then I can't 

acknowledge your exercise?

It's -- it's at a different point in the 

commercial relationship that the exercise or non 

exercise takes place. It all needs to happen the 

day the execution of the contract happens because 
that's when the question becomes is it a swap or 

not a swap? Do I report it? Do I not report it? 

Does it go in my position limits, intraday 

position limits, or not?

MR. ALLISON: And if I can come back to 

David's example, so the counter parties that have 

stopped doing option contracts and have done all 

of their business in the daily or hourly markets, 

the alternative of the daily and hourly market is 

something that is available to them, even if they 

have negotiated the option.

And the choice about whether to go into 

the daily market or whether to exercise the option 

is part of the business decision that goes into 

choosing whether to exercise the options.

So it's not as if they've had 

to -- they've created something new. That exists 

all of the time. So the question is, well, given 

it exists all of the time, why did they bother with 

option contracts in the first place? And there 

are two reasons.

One is certainty of supply. So you 

know who your supplier is. If you go into the 

daily market, you have some level of confidence 
there is going to be a supplier but you may not 

know who the supplier is going to be. So by 

negotiating the option you've got security of 

supply. You know who your supplier is.

And there's also an element of price 

protection because if you are satisfying your 

variable needs in a daily market or an hourly 

market, that daily or hourly market presumably 

has a price that is following the changes in 

demand.

So if you only have access to that high 

frequency market, you are going to be burying all 

of that shifting and market price through that

frequency. Whereas, the option, and Wally 

talked about -- the option may also have 

characteristics that give you some degree of 

price protection.

Now I'm going to argue that that degree 

of price protection embedded in the option is not 

sufficient to making a financial derivative 

because a financial derivative transfers price 

risk without transferring title to the commodity.

But these are options that yes, may 

transfer price risk but they also will win 
exercise to transfer title to the commodity. So 

they failed the most basic definition of what is 

a financial derivative. And that's an area where 

I disagree with Wally.

MR. TURBEVILLE: Unless there 

is -- they've cut me off. Unless -- unless there 

is a financial settlement option.

MR. ALLISON: Yeah, but one of the 

other parts excluded that, so.

MR. TURBEVILLE: Yeah.

MR. ALLISON: Again, part seven isn't 

dealing with the issue of whether you can cash 

settle this. Part seven is dealing with 

something about the intent to exercise.

MR. TURBEVILLE: Yeah, right. 

That's -- that's what I'm saying. But the 

intent -- what I would say is clarity -- I'm 

suggesting a different approach. My point is 

that what I'm suggesting is clarity, yes, but with 

a presumption that it's a financial instrument 

under certain characteristics and then move on.

MR. ALLISON: But I think we've all 

already agreed that if cash settlement is an 

alternative then it is a financial derivative and 
I don't think within the industry there is much 

argument about that. We're not talking about --

MR. TURBEVILLE: 

Well -- there -- there -- there are a number of 

ways to get there with --

MR. ALLISON: I mean we're talking 

about instruments to settle physically.

MR. KEMP: The root of the issue is 

physical redundancy and physical optimization 

have some characteristics that look like 

optionality. But at the end of the day, it's not 

financial optionality. And I think Wally would 

probably agree with that.

But at the end of the day, there is not 

a financial swap instrument that will keep the 

lights on or deliver gas or get coal somewhere 

and -- and that's what we're kind of going back 

and forth; is physical instruments that we use, 

physical contracts that we use to meet physical 

purposes. So that's why we separate the two 

apart.

So we use financial swaps to mitigate 

and hedge our price risk. We use our physical 

contracts to mitigate and hedge, if you will, our 
physical risk because we cannot just serve one 

side of that equation. We have to balance it and 

we cannot let the lights go off. The folks cannot 

let the gas go where it needs to go, the coal where 

it needs to go and so forth.

MR. TURBEVILLE: I remember the first 

time I heard somebody describe what you 

described, which is we may not -- we may actually 

exercise this option, even if it's against 

the -- the price -- I thought these people are 

insane. But the point being, your point is well 

taken there, which is the distinguishing factor.

The question is whether there's 

something inside the contract that can end up 

getting hedged, literally hedged. That couldn't 

be hedged and that -- what you described can't be 

hedged in the financial market because you're 

making it a non -- a non price driven decision. 

And I'm with you on that.

MR. KEMP: Yeah, and I'm just saying 

that those components who we're all talking about 

are so wrapped up together it's kind of hard to 

go back and unscramble the egg.

MR. TURBEVILLE: Well let me also 
say --

MR. WETJEN: Can I ask a real quick 

question? So let's say we can see that there's 

a need for greater clarity but maybe, to Wally's 

point, maybe if -- this is a hypothetical.

If the clarity has the effect of making 

more instruments trade options so that they have 

to be reported, and then lets also say that in the 

position limits rule a trade option is not 

considered to be included in the spec limits 

because it's not something you're easily able to 

speculate in.

And so the only other thing left then 

would be if the contract is a trade option it has 

to be reported through the form TO. How -- help 

me understand how big of a deal that is -- do folks 

think that just the obligation to report that 

alone would be enough for people just to decide, 

you know what, I don't want to do this anymore?

SPEAKER: The -- don't --

MS. DONDNAVILLE: The way the CFTC's 

interpretations work right now is that --

MR. WETJEN: I'm not asking about how 

it works now. I'm asking --
MS. DONDNAVILLE: Okay.

MR. WETJEN: -- so what I'm 

getting -- trying to get to the heart of is 

it -- and this has been something that's been 

discussed, you know, since the rule was proposed 

is there seems to be some concern about the 

obligation to report a trade option. And 

I've -- I've never -- I've always wondered, you 

know, what -- I'm trying to better understand why 

that's such a significant issue for the reporting 

entity.

MR. JESKE: Because of -- because of 

cost. Because if you don't report, you get 

pulled into part 45 and you have to create systems 

to go on report. Many end-users don't report 

today or they rely on other end-users or other 

swap dealers to do the reporting on their behalf.

MR. WETJEN: You said if you don't 

report then you have to report under 45?

MR. JESKE: If you don't report -- if 

you don't send the one billion dollar threshold

email to, I believe it's DMO, you can be pulled 

into part 45 reporting, is my read. I might be 

wrong about that.
MR. ARON: Yeah, but he's talking about 

sending the email and he's talking about form TO. 

He's talking about the simple alternatives to 

what if that -- I think that's what you're asking, 

right? It's a what if that's all you have to do 

plus the basic business records you keep anyway.

MR. JESKE: You have to determine what 

gross notional is. You've all defined it as --

MR. ARON: -- defined it as the follow 

up then maybe we get us some further guidance on 

the heat rate options if that's the one thing --

MR. JESKE: That's just an example. 

The whole concept of gross notional doesn't fit.

MR. ARON: Didn't we give guidance, the 

FAQ, that we cited in the -- for -- for physical, 

notional, didn't cover enough transactions? Is 

that the problem, or part of the -- or the problem 

you're talking about now? Because we cited in 

the 13-08, to the prior guidance that we gave on 

physical notional for the, what we thought was 

this very reason, but maybe it didn't cover 

enough.

MS. DONDNAVILLE: Physical notions.

MR. JESKE: It did -- absolutely not. 
It did not cover close to enough.

MR. ARON: Okay.

MR. JESKE: Because the 

transactions -- again, we're talking about today, 

aren't swaps. They're not swaps. So back to 

Patty's point, I always use -- try to use the kiss 

method. I learned it from somebody who was 

rather -- rather intelligent and who traded 

Treasury bond options for many years.

And we would have complex, very 

complex, portfolios. We would always come back 

to the same thing. One thing; let's make money 

and use the kiss method. And that's what I would 

advocate here. With regard to cost --

MR. WETJEN: I'm not familiar with the 

kiss method.

MR. JESKE: Keep it simple.

MR. WETJEN: Did I miss that?

MR. JESKE: There is one more -- I won't 

say it. But in terms of -- of cost here, is 

really, you know, (inaudible) is -- is to the 

interest in people reporting. So the TO form is 

quite simple and straightforward. How to 

calculate it -- I bet there's no common agreement 
whatsoever.

MS. DONDNAVILLE: Because again, you 

have to figure out if it's a trade option --

MR. WETJEN: Right.

MS. DONDNAVILLE: -- to begin with.

MR. WETJEN: Right.

MS. DONDNAVILLE: And if what the 

CFTC -- if what you're proposing is to --

MR. WETJEN: I'm not proposing 

anything.

MS. DONDNAVILLE: Okay. If what 

you're speculating about --

MR. WETJEN: I'm just trying to get a 

sense of the burden of filing a report. If that 

isn't clear, I mean I --

MR. HUGHES: Yeah.

MR. WETJEN: -- and as you can tell, 

it's a little bit difficult to understand that 

that would be a terribly burdensome thing to do, 

but I -- but, you know, I just want to make sure 

that's right or wrong.

MR. HUGHES: I think I can give you a 

very clear example. The -- I think in the rules 

it estimated that filing the form TO would take 
about two hours. Filling out the form, doing all 

of that, that's pretty easy; takes about two 

hours. I mean for us, and we've got multiple 

regulated utilities, we realize that even trying 

to utilize processes we have in place for say, 

Sarbanes-Oxley compliance, or other, you know, 

contract review processes was not going to be 

enough.

We went so far as to go hire a developer 

to develop a software system for us simply for the 

purpose of reviewing and analyzing our contracts 

to see how they evaluate according to all of the 

different tests. So you do that, you include all 

of the man hours it takes to go do that, you roll 

it up and when you get -- when you come up with 

what you think is a draft, you still have to sit 

down with all of your legal folks and do another 

review.

So we -- we think the 

cost -- it's -- it's -- it's up there. And at the 

same time, these contracts that are falling out, 

at least in our case, it's not in everybody else's 

case, but I know in our case, a lot of those 

contracts are also being reported actually in 
more detail through, you know, FERC or other 

required reporting aspects. So we feel like 

we're reporting the same information to do 

different agencies more than one time.

MR. PERLMAN: Well let me say, if we 

ended up at the end of the day with no trade 

options and position limits, and having to do form 

TO, that would be -- and we had clarity, that would 

be an improvement over where we are today.

The issue that we see, and my clients 

see, is until Dodd-Frank, they didn't think that 

they had to know where the CFTC was or what it did. 

And they have no infrastructure understanding or 

real need to be involved in CFTC regulation.

And they've made -- many of them have 

made the decision that they're not going to report 

anything. They weren't doing futures. They're 

doing swaps. So they're only dealing with swap 

dealers. They don't have any of that.

The more they get pulled into the CFTC 

universe, and maybe that's -- by implication 

you're saying that's just a matter of life was we 

know it, they're going to have to deal with it. 

But their preference would be to manage their 
business in a way that does not include this type 

of thing. And fundamentally, you guys have 

further validated the existence of the forward 

contract exemption and what we're saying is that 

we think if it's properly applied and you -- and 

you really analyze the nature of the contracts 

we're talking about, that they will fall into the 

forward contract exemption and you -- you respect 

that. And that's all good.

Now Wally said that any contract that 

can be hedged with a derivative is somehow a swap 

or something, but fixed priced forward contracts 

can be hedged with a derivative. I don't think 

that that's a test that's meaningful in this 

context. I believe it's true, but --

MR. TURBEVILLE: I said an option, an 

embedded option.

MR. PERLMAN: Okay, but what's the 

difference between that and a fixed price 

forward? At the end of the day, the question is 

are these swaps or forwards? Can we have a test 

that would respect their true nature as forwards, 

as we see it, and not just sort of default trade 

options because it's for -- for whatever reason 
we would do so?

MR. WETJEN: Yeah, and I'm sincerely 

not trying to signal a direction here. I'm just 

trying to get a sense of the merits of the 

different possible options available to us in 

terms of policy decisions. That's all.

MR. ALLISON: So as David said, 

certainty that these contracts had to be reported 

on a form TO is better than the current state. 

But it is still not free. The problem isn't 

filling out the form, the problem still is 

assembling the information that you need to fill 

out the form, which means tracking all of the 

contracts because the process by which the deals 

are created, documented, stored, tracked, is 

separate from the process that is used for 

financial derivatives.

And the systems that store these were 

never designed to be able to flag these as -- so 

there is a -- a burdensome process due to 

aggregate the information. With all of the work 

that we have done on compliance systems and 

reporting and everything else, even though we're 

not a registered entity, we've done -- we do in
fact report on part 45 and everything else for 

some of our counter parties.

Given all of the work we've done, the 

marginal cost of form TO for us, is still on the 

order of a full time equivalent. And my guess is 

that is a number that scales very, very badly as 

you go to smaller companies because the smaller 

companies will not have done the investment that 

we've done in understanding the rules, building 

the systems, investing the people. So it would 

cost them more not only relative to us, but more 

in absolute terms than it costs us.

Now, that's a very different number 

from what the Commission had in its cost benefit 

analysis. Is it a big enough number? There is 

also still the question -- the statute says, 

intended to be physically settled is out of scope. 

We have always argued that options that are 

intended to be physically settled are intended to 

be physically settled and therefore are out of 

scope as a matter of law. No shortage of lawyers 

in this room so you don't need my legal opinion. 

But yeah, certainty --

MR. WETJEN: That was actually very, 
very helpful because if you factor all of that in 

then you have to start thinking about, again, 

when you're looking at number of policy options 

here, what are, you know, what are the benefits 

to us in having the report in light of the burden. 

So that was helpful, thanks.

MS. DONDNAVILLE: And I think Jim's 

right. If you take it down to the scalable 

by -- by entity, the 2000 municipal entities 

across the United States, municipal utilities, 

all small entities, they all enter into commodity 

options of some sort or forward contracts with 

embedded optionality of some sort, variability of 

some sort.

None of them have the systems to be able 

to report what they have always viewed as physical 

market transactions. Cash market transactions 

in a format that would be anywhere comparable to 

what the CFTC gets from its regulated entities.

MR. ALLISON: And that's one of the 

factors behind the agree to disagree; not much of 

a --

MS. KIM: Since we -- since we are 

running well past our allotted time, let me just 
try to shift the discussion a little bit. As some 

of you pointed out, there's a range of actions 

that we, the staff or the Commission, can take to 

address these very complex interpretive issues.

And so I want to focus a little bit more 

on what we, at the staff of the Commission level, 

can do in the immediate term in providing greater 

clarity and what are some of the major areas that 

you would like to see us address in the form of 

a guidance, advisory, clarifying examples.

MR. ALLISON: So, I mentioned in my 

opening comments that -- that we have some 

language that we think is helpful from the 

perspective of interpretive guidance. But 

again, my request is if you're going to give us 

interpretive guidance, it has to be something 

that we can actually rely upon. So I'm not a huge 

fan of further examples because further examples 

don't really give me anything I can rely upon.

Interpretive guidance such as the 

guidance that was used to, at least temporarily, 

fix the problem with the use contracts and the 

infamous however paragraph, that seems to have 

solved that problem at least for now. So again, 
we've got some language. I alluded to and David 

alluded to some -- that would be a path forward 

that I think you could implement more quickly than 

getting to a new rule.

MS. DONDNAVILLE: Well, and it's not a 

new rule. Again, the CFTC's interpretation, 

which is what was issued in August of 2012, can 

be changed by the CFTC. You can, I guess, the 

staff could issue guidance as to what it meant in 

the interpretation in a, perhaps, a quicker 

period of time, or they could open a rulemaking 

and have all of this discussion again. But I 

think you have the interpretation. You have the 

ability to issue interpretations, or fix 

interpretations.

MS. BERGLES: AGA did make a request 

for interpretive guidance on February 22, 2013, 

with a set of very, very specific examples, which 

still remains pending. But what ultimately we 

would like to see is the Commission respond to the 

comments filed by an order the comments that were 

filed on October 12, 2012.

We believe that that is probably the 

most way to achieve certainty other than further 
guidance. And in terms of the OGC guidance on the 

storage and transportation agreements, we'd also 

like to see that rolled into a final rule and not 

sitting out there as guidance.

MR. PERLMAN: Yeah, it would seem to me 

that, in agreement with what the other folks had 

said, that something like the OGC clarification 

could occur in the short run and then you could 

wrap that and the least like component into a 

further rulemaking sort of similar to what's 

happening with the de minimis no action letter 

being followed up by a rulemaking. So we can have 

an interim solution that deals with the pressing 

problem, but in a legally sound and more 

definitive way to get the answer settled, sort of 

for once and for all with everybody having the 

notice and comment opportunity.

MS. DONDNAVILLE: And most critically, 

I think you have people around this table and

people elsewhere who are very interested in 

helping work on the language so that what happens 

is not that the CFTC comes out with additional 

interpretations that don't work for our industry.

MS. KIM: Okay. Then with that, we'll 
close this session. And as was mentioned earlier 

today, the comment -- we are receiving comments 

up until April 17, I believe. So each of you will 

have a chance to -- as well as the public, will 

have a chance to follow up on all of the topics 

that we touched on at this session. Thank you 

all.

SPEAKER: Thank you very much.

(Off the record.)

MR. REMMLER: Well, I see we still have 

one panelist we're waiting for but I think I'll 

get started since it's after 1:30. This is the 

panel three for the roundtable, special entity de 

minimis threshold for swap dealing to government 

owned electric and natural gas utilities.

My name is Erik Remmler. I am the 

Deputy Director in the Division of 

Registration -- Division of Swap Dealer 

Intermediate Oversight. I'm the Deputy Director 

for Registration and Compliance. I have with me 

here, Israel Goodman, who is on my staff and who 

is working on this issue and has helped work on 

the proposed rule that the Chairman announced 

earlier today.
Before I get started, I've been asked 

to remind all of the participants on the panel 

that -- to use their microphones they have to 

press the little red button to turn it on and then 

press it to turn it off and to please speak 

directly into the microphone so that your 

comments can get -- can be recorded.

I want to thank you all, the 

participants, for coming in today. I know some 

of you have actually come in from the West Coast, 

so I appreciate your making the trip. We do see 

this is a very important topic. What you say here 

today will go a long way to helping the Commission 

and the staff in crafting a more appropriate 

longer term solution for the utility special 

entity de minimis issue.

I'm going to briefly provide some 

background information on special entities and 

the swap dealer de minimis threshold and then 

summarize the history behind the development of 

this issue here at the Commission.

After that introduction, I'll ask the 

participants to introduce themselves and provide 

any remarks that they may have. Time permitting, 
we will then ask some questions for the panel and 

with the desire of generating some open 

discussion on the topic.

So to begin, the Dodd-Frank Act for the 

first time required persons dealing in swaps to 

register with the Commission as swap dealers. 

The act also provides additional protections for 

persons categorized as special entities when 

dealing with swap dealers.

Specifically, Commodity Exchange Act 

Section 4s(h) imposes on swap dealers specific 

prohibitions on fraud and manipulation, with 

respect to special entities and subjects swap 

dealers to heighten business conduct standards 

when they advise or act as counterparties to 

special entities.

The term special entity generally 

includes federal agencies, state and local 

governments, and their agencies and 

instrumentalities. The definition captures 

state and certain federally owned energy and 

natural gas operations.

As the Commission has noted in adopting 

the rules, special entities that assume risk 
through the use of swaps also expose the citizen 

beneficiaries of their activities to the risks 

from the swaps. When a special entity suffers a 

loss from a swap, the special entities' 

beneficiaries, therefore ultimately bear the 

burden of any losses that are incurred.

Consistent with the congressional 

intent of creating a special entity category and

promulgating the swap dealer definitional rule, 

the Commission set a lower de minimis level of 

dealing activity with special entities for 

purposes of de minimis exception to swap 

dealer -- to the swap dealer registration 

requirement. That level, as I'm sure all of you 

know, is -- was set at 25 million of the gross 

notional amount of dealing activities with these 

entities. Any dealer who deals at that level or 

higher with special entities must register as a 

swap dealer.

A de minimis exception by its nature

will deprive counterparties of the protections 

provided by dealer registration and regulation. 

And implementing the de minimis exception, the 

Commission stated that it sought to balance the 
interests advanced by the exception against the 

risk that if applied in an overbroad manner, the 

exception could undermine the regulatory 

protections and specifically, with respect to 

special entity counterparties, the special 

protections as such entities warrant, as 

determined by Congress.

Following the adoption of the 

special -- of the swap dealer definition rule, a 

number of organizations representing government 

owned electric and natural gas utilities 

submitted a petition requesting that the 

Commission amend the de minimis exception, to 

exclude certain utility operation related swaps 

entered into with utility special entities from 

the 25 million dollar de minimis amount. Many of 

the petitioners are represented here today on the 

panel.

In effect, the change requested would 

allow dealers to treat those swaps like swaps with 

non special entities for purposes of determining 

whether they need to register. The petition 

stated that the amendment was necessary to 

increase the number of potential counterparties 
for these entities and preserve cost effective 

access to customize non financial commodity swaps 

that utility special entities need to hedge and 

mitigate their commercial risks.

Since some of the petitioners are 

represented here, I'll let you describe the 

reasons why this change is needed and hopefully 

provide some background as to why it's 

appropriate given the nature of your activities.

In response to the petition and to 

subsequent requests for no action relief, the 

Division of Swap Dealer and Intermediary 

Oversight issued staff letter 12.18 granting no 

action relief. The relief generally created an 

$800 million de minimis level for swap dealers 

entering into utility commodity swaps with the 

utility special entities.

The letter also imposed a number of 

additional conditions for entities seeking to 

rely on the relief. Subsequent to issuing the 

letter, the Commission staff heard from the 

petitioners and others that potential 

counterparties were still not making themselves 

available to transact with utility special 
entities.

Among potential reasons provided, was 

that the requirements imposed on counterparties 

in the staff letter were still deemed too 

burdensome for the relevant dealers to continue 

dealing.

In response to these concerns, the 

Division recently issued staff letter 14.34, 

which supersedes and broadens the relief. The 

new letter, in effect, subjects utility 

operations related swaps with utility special 

entities to the $8 billion general de minimis 

threshold and remove the number of conditions 

that were in the first staff letter.

Letter 14.34 provides that the relief 

granted will remain effective until any final 

Commission action is taken, with respect to the 

petition that was received by the Commission.

The purpose of this roundtable is to 

highlight the need to address the issues utility 

special entities are experiencing so that a 

longer term and workable solution can be 

implemented. As Chairman Wetjen announced, the 

Commission is considering a proposed rule 
amendment to address this issue and the 

discussion we have here today will help inform the 

Commission and the staff in that effort.

Before I turn to the panelists, I 

noticed that Commissioner O'Malia joined us. I 

don't know, Commissioner, if you want to make any 

remarks at this point or?

MR. O'MALIA: Thank you. Well, I'm

pleased to have this discussion and I'm pleased 

to have in circulation a rule change because 

that's the appropriate way to address this. The 

abuse no action process is -- doesn't afford 

anybody the comment period or cost benefit 

analysis. So I'm glad that we're taking the 

right steps to fix the rules where they need 

fixing and I'm supportive of not distinguishing 

between special entity utilities and any other 

end-user and to put them on a level playing field 

to make sure that they're -- they're able to do 

their business in the same direct manner 

everybody else is and not burden them with an 

additional set of rules that has thus far limited 

their counterparties to mainly swap dealers and 

to free them up to the regional players that they 
deal with on -- that they had been dealing with 

on a regular basis to deal with their, you know, 

regional utility concerns.

I'm mindful that markets 

aren't -- there's not a global or a national 

market for energy. It is a regional market and 

trading around that is essential to meet, you 

know, regional players in those markets. So I 

look for -- I haven't read the proposed rule that 

just landed on my desk today so I look forward to 

reading that and turning around very quickly a 

document that is responsive to the concerns of the 

end-users.

MR. REMMLER: Thank you. I think that 

at this point we'll start with the panelists; 

starting on my left with -- with Bill Rust.

MR. RUST: Good afternoon. My name is 

William Rust and I am the Compliance Director for 

the Energy Authority. I appreciate the 

opportunity to be a member of this special entity 

de minimis threshold panel this afternoon. But 

also I would like to thank the CFTC and acting 

Chairman Wetjen for the March 21 no action letter, 

as well as the proposed rule that was just 
announced today. We certainly would like to see 

the relief made permanent and do appreciate that.

Headquartered in Jacksonville, 

Florida, the Energy Authority is a nonprofit 

corporation owned by eight public power electric 

and natural gas utilities across the United 

States. We provide risk management service to 

our owners, as well as contract customers.

The Energy Authority provides front, 

back, and mid office services to 40 plus public 

power clients, representing approximately 29,000 

megawatts of electric generation, which includes 

clients as small as 50 megawatts of load up to 

larger systems closer to 6,000 megawatts of load.

Our business model at the Energy 

Authority allows us to provide the same level of 

service to both the smaller and the larger 

clients. Our clients serve both electric and 

natural gas end-users and the Energy Authority's 

primary corporate objective is to partner with 

public power to hedge risks by giving our clients 

access to wholesale power and natural gas markets 

across the United States.

To manage risk, we transact both 
physical and financial products, primarily in 

electric power and natural gas from next hour out 

through multiple years. We partner exclusively 

with public power clients and offer our clients 

access to a broad spectrum of counterparties, 

including banks, major oil companies, marketers, 

producers, RTOs, ISOs, investor owned utilities, 

as well as other public power entities.

Our clients use natural gas a fuel to 

generate electricity and also sell fixed price 

natural gas and electricity to end-use customers 

such as residential, retail, commercial, and 

industrial load.

Our clients strive to provide reliable 

low cost energy to their customers and the swaps 

used on the wholesale side help manage the inputs 

that ultimately determine the price paid by the 

household purchasing electricity or natural gas.

Our clients are geographically 

dispersed across the United States, but yet all 

depend on liquid markets to implement the best 

possible risk management program. The nature of 

our business requires that we take different 

approaches, depending on the region and the 
individual client.

For example, our clients in the Pacific 

Northwest have found that bilateral electric 

power swaps meet their needs most effectively, 

while clients in the East can use natural gas 

futures combined with swaps to meet their hedging 

needs. We have found that liquidity for long 

term transactions greater than three years is 

much higher in the bilateral swap market, 

relative to the futures market.

The $25 million de minimis threshold 

for swap transactions with special entities has 

negatively affected our clients' businesses. 

For example, our -- our clients in the Pacific 

Northwest have lost over half of their bilateral 

swap counterparties. We have been able to 

continue to hedge but remain concerned about the 

increased costs associated with a less liquid 

swap market.

We appreciate the need to ensure that 

unsophisticated non utility governmental 

entities should be protected from aggressive swap 

transactions. However, the Energy Authority was 

created for the purpose of helping out our clients 
in helping them manage their risks. Our business 

model depends on sound risk control practices 

that are implemented to protect our clients while 

affording them access to the best possible risk 

management program. Thank you.

MR. TRACY: Good afternoon. My name 

is Jim Tracy. I'm the CFO for SMUD, which is 

Sacramento Municipal Utility District. We 

certainly appreciate the opportunity to be able 

to address this panel this afternoon.

SMUD is a special district that serves 

most of Sacramento County and we have about 

600,000 retail customers. SMUD has always 

ranked real near the top in the country in terms 

of customer satisfaction over the last several 

years, you know, J.D. Powers surveys. But one 

element of that has been our ability to set rates 

for two years and basically be able to tell our 

customers ahead of time, almost a year in advance, 

what the change is going to be.

Many of our very large commercial 

accounts run businesses that require very large 

amounts of power. So an example, Intel, Aerojet, 

air products type companies, internet servers, 
and light manufacturing. Having the ability to 

see what their price is going to be and having it 

fixed for two years is really important to their 

business models.

So about 50 percent of SMUD's power is 

produced with our own gas fire generation. And 

in order to achieve the rate cycle that we do, and 

we do this every two years, we set the rates, we 

really need to fix the price of gas for about a 

three year period. And so at today's prices, for 

us, that amounts to about $600 million of gas that 

we would be contracting for. When prices were up 

closer to $8, that would have been like $1.2 

billion.

Also important to know is that each one 

dollar change in the price of gas, for that three 

year period, results in about $150 million change 

in our overall cost, which is about four percent 

of the retail rates. So trying to hedge this 

through exchanges poses two problems.

The first, which will be discussed here 

and has been discussed, is that the products 

actively traded on an exchange are imperfect 

hedges. The price of gas in Louisiana doesn't 
change and lockstep with the gas in California. 

You are out there in the -- during the energy 

crisis, you knew this in spades.

But the second is the higher cost of 

collateral. And I want to explain how that 

figures into our business model. With our strong 

balance sheet and our ability to set fixed prices 

for the recovery of whatever we entered into in 

the swaps, so it's basically matching fixed 

retail prices with fixed wholesale cost of gas.

We're able to negotiate contracts with 

our counterparties that allow for up to $15 

million of credit for market to market. We have 

had in the past like 16 active counterparties. 

And by spreading our exposure over the 16 

different parties, we had almost $250 million of 

credit before collateral posting was required. 

Of course, exchanges require 100 percent posting.

So over the last year, half of our 

counterparties have stopped trading with us. 

This has reduced our available credit by almost 

$120 million. I have stepped up -- I have told 

our Board that we're fast reaching the point where 

the cost of just maintaining additional 
collateral would become too expensive to maintain 

the level of hedging that we're doing. So 

whether we have actually posted collateral or 

not, we have to have the cash on the balance sheet 

or we have to have letters of credit ready if the 

market prices change so that we can meet the 

collateral posting requirements.

To put it in perspective, each $100 

million of reserved cash right now is equal to 

about $400 million a year in cost. That's about 

$10 million overall, which it could end up costing 

us. So the alternative is to go to our Board and 

talk to them about passing through the changing 

fuel prices to our customers using a fuel cost 

adjustment.

This, of course, would have an impact 

on our local business in Sacramento County, not 

to mention the approximately 25 percent of 

residential customers who are on low income 

discount rates.

We on a regular basis report 

significant risks to our Board. And we do this 

once a month. And I'll tell you that our 

Board -- we just reported earlier this week and 
our elected Board was very appreciative of the no 

action letter recently granted.

The ideal, of course, would be to have 

a permanent fix. And I'd say that SMUD, again, 

certainly appreciates the opportunity to provide 

some of the detail of how special entity rule has 

impacted our customers.

MS. SCHAEFFER: Good afternoon. My 

name is Virginia Schaeffer and I'm with the 

Bonneville Power Administration and an attorney 

with the Office of General Council and based out 

of Portland, Oregon. And I too want to add my 

thanks to the Commission staff and most 

especially to Chairman Wetjen for the most recent 

no action letter and then -- I've not had a chance 

to review it, but the proposed rule that's come 

out this morning. And as others have mentioned, 

join in with the recommendation that we all have 

that -- that we need some permanent solutions to 

the special entity de minimis threshold issue.

So with regards to the adverse impact 

of the special entity de minimis issue, for 

Bonneville there has not been quite a direct 

impact. Instead, what Bonneville has seen 
though is an overall drop in the number of 

counterparties, especially counterparties for 

longer term physicals and swaps in general.

So there's -- we've just seen an overall 

drop in the liquidity of the market. I'm not 

quite certain if that is necessarily tied to the 

concerns over the special entity issues, and or, 

just the overall regulatory burden that 

Dodd-Frank, in some part, is imposing on the lot 

of counterparties.

So at this point I'd like to take the 

opportunity to tell you more about what a diverse 

group the special entities are because Bonneville 

is a bit unique compared to some of our other 

special entities that are represented here today.

We're one of four federal power 

marketing agencies within the Department of 

Energy. We're self funded through our rate 

payers, not taxpayer funded. And Bonneville 

is -- markets wholesale electric power from 31 

federal hydroelectric projects on the Columbia 

and Snake Rivers. We also market the electricity 

from one non federal and nuclear plant and from 

several other small non federal sources. And 
while Bonneville does not actually own any of the 

generation, we do supply about one third of the 

electric power used in the Pacific Northwest.

Now, Bonneville also operates and 

maintains about percent of the region's high 

voltage transmission system and our geographical 

area service covers Oregon, Washington, Idaho, 

Western Montana, and small parts of Wyoming, 

Utah, Nevada, California, and Eastern Montana. 

So we have a fairly large footprint.

And as I noted earlier, Bonneville is 

self funded. We recover our cost through our 

rates and obviously it's in our best interest and 

our customers' best interest to keep our costs 

low, which includes working to mitigate our risks 

and in -- in the most efficient way possible. And 

to give you an idea, one other item I wanted to 

pass on, but in terms of our overall operating 

revenues for fiscal 2013, was $3.35 billion. So 

we're -- we do have a rather sizeable energy and 

transmission business.

So Bonneville's statutory 

responsibilities are to meet the power needs of 

its preference customers. And those are the 
consumer owned utilities in our region, and that 

includes the public utility districts, the 

people's utility districts, cooperatives, tribal 

utilities, municipalities, and other federal 

agencies. And again, as I said, within that 

large geographical area.

Bonneville also sells power to investor 

owned utilities and some direct service 

industries in the region and when there is a 

surplus of power in the Northwest, then we sell 

to marketers and utilities in Canada, as well as 

elsewhere in the Western United States.

Now, Bonneville's challenge, of 

course, is that we're primarily a hydro base 

system. It's 80 percent of our generation is 

hydro sourced. And consequently, we're very 

much subject to a supply issue, as it were, of our 

fuel. And -- and the timing of when that fuel is 

available is something that we can't control, 

unlike many others that utilize either coal or 

natural gas or other types of generation.

In addition, there are many competing 

interests for the water. There's irrigation, 

transportation, flood control, recreation, 
conservation, such as ensuring that there's 

sufficient instream flows to permit the passage 

of fish up and down the river, and with rare 

exceptions, pursuant to the various federal 

statutory provisions, these competing interests 

take precedence over the -- our ability to 

generate electricity. So all of those things 

mean that we have some real -- a lot of balls to 

juggle in order to be able to make sure we have 

sufficient generation on hand to meet our load 

demands when it is needed.

So -- because spring time comes, we get 

a lot of snow melt and get a lot of water but there 

isn't always a lot of demand. So whereas, come 

late summer, the snow melt is gone, it's hot, 

people have their air conditioning on, all of 

those things we tend to then, of course, start 

having the increased demands for electricity but 

have less fuel available.

So consequently, we are always out 

there looking for ways balance our system, 

both -- well primarily we have to balance it 

physically, but that can be done through lots of 

different tools as others have mentioned already.
And again, to also reiterate some of the 

other shortcomings of our -- of our system is that 

we have very little storage capacity and so 

consequently, Bonneville has, for decades, made 

extensive use of short term and long term purchase 

and sales, contracts, by using -- for generation, 

by using instruments such as forwards, and 

futures, and swaps, and options to make sure that 

we can meet our customer demands.

And we have successfully used these 

instruments to hedge and mitigate both our supply 

and price risks in an effort to keep our costs low, 

because again, we are a not for profit agency and 

we also want to minimize the price volatility for 

our rate payers.

We have also participated and continue 

to participate in financial instruments. But as 

Jim was mentioning like with SMUD, we do have the 

issue of being very costly in terms of posting 

margin. Most of our transactions we are 

bilateral and we generally don't need to post 

collateral for -- in fact, I'm not aware of a 

situation where we do post collateral for our 

customers, our counterparties.
And obviously that's not the case when 

we are dealing with going through clear 

transactions where we do have to post margin and 

it does impose a much greater burden in terms of 

monitoring our cash flow and ensuring that we can 

meet those margin calls as they come.

So to wrap it up, I guess as the 

Commission evaluates its rules and regulations 

for the utility special entities engaged in 

utility related swaps for the operational hedging 

or risk mitigation purposes, what we're trying to 

make clear -- I'm trying to make clear is that all 

of us have been involved in this for years and we 

have very significant core competencies in this 

area.

This is not an area where there have 

been a history or any particular problems, unlike 

the issues surrounding other types of financial 

derivatives. Interest rate swaps, of course, 

are things that come to mind with regards to 

municipal entities in the past.

So we respectfully request that utility 

special entities be allowed to compete on a level 

playing field with the other utilities that are 
out there and, you know, let us do our business 

as usual as we always have and as we have done it 

well. So thank you.

MR. NAULTY: Good afternoon. My name 

is Terry Naulty. I'm the General Manager and CEO 

of Owensboro Municipal Utility. We're the 

largest municipal utility in Kentucky; provide 

electric, water, and telecom services to the 

third largest city in the state.

I'm going to provide a quick summary of 

how the special entity threshold has impacted 

OMU. First, I want to thank the Commission, and 

especially Chairman Wetjen for the March 21 no 

action letter. We've already seen benefits from 

this policy change and applaud the Commission in 

its efforts to -- to make permanent the change and 

to just announced rulemaking.

My participation on this panel is an 

indication of the importance of this issue to 

smaller utilities, unlike my colleagues here who 

represent some of the larger public power 

entities in the country.

We generate electric power with 

multiple coffered units and we have significant 
surplus capacity that's hedged in forward markets 

to provide revenue certainty, offsetting fixed 

and variable cost associated with that surplus. 

This operational hedging activity insulates our 

rate payers from wholesale power, market priced 

volatility, and enables OMU to provide low and 

stable electric rates.

A number of factors that affect our need 

and ability to hedge operational risks, but I 

don't focus my comments on two aspects; the 

physical nature of the electrical grid in the 

Midwest and Southeast, and secondly, how we've 

been impacted in our -- in our actual hedging 

transactions.

The grid in the Midwest and Southeast 

was originally designed to allow individual 

utilities to move electric power from their 

generating stations to their customers. There 

was a very -- there is -- excuse me. There was 

very limited interconnectivity between 

companies, but there has been significant 

investments made to improve that 

interconnectivity, especially for those 

companies that are located inside of a regional 
transmission operator market such as PJM and 

MISO.

OMU, like -- like many public power 

entities in the Southeast and in the West, were 

not part of an RTO. Geography, physics, and 

economics dictate that the only true 

interconnection between utilities are with our 

neighbors. Swap dealers provide limited 

liquidity for standard products at liquid trading 

points that are remote to the physical delivery 

points where we buy and sell wholesale power.

Prior to the special entity threshold, 

these inexact hedges were not the only option 

available to OMU because regional utilities and 

their trading affiliates were willing to enter 

into swaps with OMU at points that were at or near 

our physical delivery points. Like us, these non 

swap dealer counterparties are physical players 

in our markets. They share our need to hedge at 

points in the grid that are not the most liquid 

trading hubs and thus recognize that standard 

products are not optimal hedging mechanisms.

So prior to the March 21 letter ruling, 

these non swap dealer counterparties have not 
been willing to enter into hedging transactions 

with OMU due to the risk that they'd be draw into 

the swap dealer classification. This has had two 

significant affects.

First, we lost about a third of our 

counterparties. But that third of our 

counterparties represented 70 percent of our 

historical hedging activity. This resulted in a 

substantial loss of term liquidity that my 

colleagues have talked about. Traditionally, 

bilateral trades with regional (inaudible) whose 

term positions offset OMU's short versus long 

positions, created an incentive for entering into 

term transactions.

These relationships were enhanced by 

our bilateral credit agreements. The move to 

swap dealers and exchanges as a result of the 

special entity threshold, coupled with the 

winter's polar vortex, has been extremely 

detrimental to OMU because those swap dealers 

have been focused on the near term markets and 

managing the volatility in those near term 

markets and have lost interest in the long term 

markets.
Second, OMU has incurred increased 

collateral on credit costs. And Jim talked about 

this but I'll give you another example. With the 

loss of trading counterparties, our two options 

for executing term hedging with swap dealers was 

with either swap dealers or on the exchanges.

In reality, the swap dealers from 

which -- with which we had (inaudible) in place, 

widened their bid as spreads, knowing that our 

regional counterparties were no longer trading 

with us. As a result, executing the hedges on the 

exchange was a better option for OMU. But still, 

at a significant incremental cost.

We had to pay fees for execution and for 

the first time, we had to provide cash margining. 

Previously negotiated collateral agreements with 

counterparties permitted hedging without cash 

margining based upon the strengths of our 

respective balance sheets.

Over the last 18 months, our margin 

requirements have ranged from 4 million to over 

10 million, with less term hedging than we 

would -- what we believe is optimal. For 

utilities serving just 26,000 customers, it's a 
significant cost.

Additionally, stress testing of the 

positions has resulted in additional reserve 

requirements to ensure that we have adequate cash 

liquidity to meet margin calls in high volatile

markets. These are all extra costs that we have 

to pass through the right payers with no benefit 

relative to the pre special entity rules.

Finally, I want to ensure the 

Commission that OMU and the public power industry 

have the expertise and the risk management 

systems in place to understand these markets, the 

property value -- to properly evaluate the credit 

price and operational risks associated with our 

operational hedging activity. It's a core 

competency of all power -- public power companies 

with marketing commodity risk exposure.

Despite the ups and downs for -- of for 

profit energy traders, not a single public power 

entity has defaulted since 1998. Likewise, 

related swaps -- operations related swaps of 

public power utilities pose really no systemic 

risks. And I thank you for your attention.

MR. HOWARD: So you have to turn it on. 
Good afternoon. Chairman Wetjen, Commissioner 

O'Malia, staff, thank you for the opportunity to 

participate today. My name is Randy Howard. 

I'm with Los Angeles Department of Water and Power 

and I've been here a number of times on this topic 

meeting with staff. And so I appreciate the 

willingness to continue meeting with us and 

working through these -- these issues.

Los Angeles Department of Water and 

Power is a Department of the City of Los Angeles. 

We're the country's largest municipal utility. 

We serve about four million people. I'm going to 

try not to repeat some of the things you've heard 

hear but just go over some of the specific impacts 

related to Los Angeles.

So our annual fuel and purchase power 

budget is approximately $1.5 billion per year. 

So as you can imagine a $25 million de minimis 

level is a very small quantity for us as a utility. 

We have physical facilities in seven Western 

states feeding into the City of Los Angeles.

Our customers are our owners. We don't 

have a group of shareholders that we can turn the 

risk and the burden to. So Mr. Tracy spoke about 
something they're contemplating at SMUD as to how 

they might move to -- move the risk onto the rate 

payers. Due to this particular rule and the loss 

of some of our counterparties, the City of Los 

Angeles moved forward with taking the risk for 

some of our hedging and moving it onto the burden 

of our rate payers.

They -- the governance went forward 

with a rate action and quarterly we take all of 

the risk related to the cost of -- of our fuel and 

we impose it in a rate onto our rate payers. This 

is had a significant impact to them. Having that 

many customers, we have 300,000 low income and 

lifeline customers, we have many customers that 

are fixed income, and having those types of 

adjustments on their bills have a direct 

impact -- they have no ability to risk -- I mean 

to hedge themselves.

And so we have had that impact related 

to this rule and we appreciate right now the no 

action letter and then the proposed change in the 

rule because that will have a very significant 

ability to go back and have the counterparties 

necessary to hedge.
We all here have that obligation of 

keeping the lights on 24 hours a day, 365 days a 

year, regardless of the climate conditions. 

This winter was an extreme winter for Los Angeles 

as it was for the East with the polar vortex. 

We're going through an unprecedented drought. 

That drought is impacting our hydro abilities.

We don't have the reserve, water, 

behind the reservoirs and the damns, to meet some 

of our needs. Therefore, we need to burn more 

fuel. This year, our fuel usage is up 

dramatically, as well as our emission profiles 

associated with that and so there's a great 

uncertainty to our rate payers as to some of the 

costs associated with that.

The other issue that's hitting us more 

recently is the ground is shaking. We have 

earthquakes in Southern California, underneath 

of our building in L.A. We were able to hedge and 

have more options available to us previously that 

were some of our risk mitigation related to the 

potential of earthquakes and droughts. Many of 

those positions we have let go as a result of not 

having the appropriate counterparties.
So we're hopefully to get the permanent 

oil change. We do appreciate the no action 

letter and think it will have a direct impact on 

our ability to transact again with our 

counterparties. And going forward, we would 

like to continue working with the staff and the 

Commissioners associated with this activity.

MS. DONDNAVILLE: Thank you and good 

afternoon. I appreciate the opportunity to be 

here. My name is Patty Dondnaville. I'm a 

partner at Reed Smith and I have worked with the 

not for profit electric group since 2010 and 

written more than 45 substantive comment letters 

to the CFTC on various topics.

I'm on this panel because I drafted the 

petition for rulemaking in 2012, asking the 

Commission to exclude from the $25 million sub 

threshold, a very narrow category of operations 

related swaps that these entities across the 

United States that are special entities need to 

run their electric businesses. And it would also 

impact those who have special entity gas 

utilities as well.

What the petition is not is it is not 
in any way to affect the $25 million sub threshold 

as it would impact interest rate swaps. So a 

counterparty who has not yet registered as a swap 

dealer would still have to consider those 

interest rate swaps with the utility special 

entity in considering whether or not it exceeded 

the threshold.

Another thing that the petition is not 

is an exclusion to allow the utility special 

entities to speculate, deal, or trade in those 

types of utility operations related swaps. It is 

specifically to allow them to do what they do, 

which is deliver power 24/7 at affordable rates. 

The best way to hedge that, and in that context, 

would mean hedge or mitigate commercial risks.

Those commercial risks exist. These 

are not risks that these utilities assume by 

entering into these swaps. The swaps that we're 

talking about are risk mitigating swaps. But to 

allow them to enter into those swaps as part of 

their core competency and to have access to non 

registered swap dealers in the these regional 

markets in order to continue to provide their 

electric service to their constituents.
I'm happy to answer any questions about 

the petition. I look forward to reading the 

proposed rules and I'm sure that we will be 

commenting. Thank you.

MR. CAMPBELL: Good afternoon. I'm 

Lael Campbell, Director of Government and 

Regulatory Affairs for Exelon Corporation. 

Exelon is the nation's leading generator and 

supplier of electricity in the competitive power 

markets. Exelon's consolation business 

provides physical energy products and services to 

approximately 100,000 business and public sector 

customers and more than a million residential 

customers.

I'm here today on behalf of the Edison 

Electrical Institute. EEI is a trade 

organization for all of the investor owned 

utilities in the United States and EEI's members 

serve over 70 percent of all electric customers 

in the U.S.

EEI members are physical commodity 

markets participants that rely on swaps primarily 

to hedge and mitigate their commercial risk. At 

the outset today, Commissioner O'Malia spoke 
about, you know, turning the discussions today 

into action and in this case, the Commission a 

week or so ago already took action, which we 

greatly appreciate and it was great to hear acting 

Chairman Wetjen talk about taking the next step 

of formalizing some of these -- some of this into 

a formal rule.

EEI appreciates the issuance of the 

March 21 no action letter on the de minimis limit 

applicable to utility special entities, which 

recognizes the lower risk of swap transactions 

that occur between end-users. Many EEI members 

have longstanding commercial relationships with 

municipalities, such as the ones at this table, 

power authorities, and other special entities as 

part of our core electric generation supply 

businesses.

Although swap transactions with these 

special entities are not the most common form of 

transaction we would engage in. The no action 

letter, the recent no action letter addresses 

some of the material concerns that prevented EEI 

members from engaging in those swap transactions 

over the course of the last few years.
The March 24 no action letter is a great 

improvement and it is appreciated, but there are 

some remaining concerns. Most notably, there 

remains some uncertainty as to whether a person 

meets the definition of a utility special entity.

Without clarification from the 

Commission, that a person can in good faith rely 

on a representation from the counterparty, that 

they do indeed meet that definition, EEI members 

may believe that it is their burden to make that 

determination themselves. And more 

importantly, that the -- that the member bears the 

significant risk of getting that determination 

wrong.

So hopefully the Commission could 

clarify to some extent that -- that 

counterparties can rely on the representation 

from -- from -- from their counterparty that they 

do meet the definition of the special entity. 

That would alleviate a lot of the risk 

that -- that -- that we still feel remains to some 

extent.

Finally, I would also like to discuss 

the concerns of EEI members and other end-users 
with the general de minimis special and the 

current transition from eight billion to three 

billion in 2017, this going to occur absent 

Commission action. This sudden arbitrary drop 

impacts the ability of utilities to engage in long 

term planning. Commodity prices are unstable 

and vary considerably over time. And the 

certainty of a stable consistent de minimis 

threshold will assist EEI members in managing 

their risks.

Also, given the variable nature of 

commodity prices, the Commission can't know or 

even meaningly evaluate what the cost benefit 

impact of such a dramatic reduction in the de 

minimis threshold will be five years from now. 

The current proposed drop in the de minimis 

threshold also will have an impact on the recent 

Commission no action letter from March 21, as 

these swaps are now included in the eight billion 

general de minimis threshold that is going to drop 

to three billion.

Having the Commission provide 

additional certainty on this issue by clarifying 

the Commission action with the opportunity for 
comment, will be taken prior to a reduction. The 

de minimis limit will provide additional helpful 

certainty to the market. Thanks again and I look 

forward to the discussion.

MR. REMMLER: Thank you. Jerry, and I 

see you came in a little late.

MR. JESKE: Yes, Jerry Jeske, Chief 

Compliance Council from Mercuria Energy Trading. 

I'll make it brief. We come at this from a little 

bit different angle and we -- we are not a 

participant today because of the rule. And the 

cap that was put on, and as many folks have been 

speaking up here today, would take us out of the 

equation because we're an end-user that has no 

interest in becoming a swap dealer.

So I just want to say a heartfelt thank 

you to Commissioners Wetjen, Commissioner 

O'Malia, and staff for issuing the March 24 no 

action 14.34. I think it was well reasoned and 

just really appreciate the attention to this -- to 

this matter.

We can, you know, try to serve the 

greater public interest of creating liquidity for 

what is obviously an essential business across 
the United States. We can fill that void, we can 

be part of the process. But as I think Lael was 

mentioning, there is this looming three billion 

threshold ratcheting down, so to speak, that 

everyone is going to have to take into 

consideration.

So effectively, with that looming out 

there, folks will create at, again, an arbitrary 

level because we can't just focus on electricity. 

We also have to look at the gamut of energy, fuel 

oil, oil, natural gas, across the board and if you 

are going to manage your business in a way that's 

going to be arbitrarily limited at some point in 

the future, you really have to put that cap in now, 

which will again, reduce liquidity unfortunately 

and so we're hopeful that the Commission can not 

only address this as -- as Commissioner Wetjen 

said in terms of formal rulemaking, but also pay 

attention to this potential ratcheting down. 

But thank you again and we really appreciate the 

no action.

MR. WETJEN: Lael, I'm glad you raised 

the issue you did about the reps. Is there 

anything else along those lines that we should 
anticipate comment letters pointing out in 

response to the proposal, assuming we can get it 

released?

MR. CAMPBELL: You know, the other 

issue we've explored is -- well, there's a few 

things, right. We've spent a lot of time and 

energy putting in internal policies to prevent 

swap transactions with special entities since it 

was, as part of our Dodd-Frank implementation, 

our biggest risk. So in order to use, for our 

company, in order to use a no action letter, we're 

going to have to actually change some of our 

internal policies. And also the reps 

themselves, you know, I think the Commission 

should consider whether all of the reps are 

necessary.

It is going to involve changing 

agreements with counterparties to a certain 

extent. Right now, you know, we were talking 

with the ICE folks earlier. ICE eConfirm is 

probably the most common platform used by energy 

market participants. Right now the confirmation 

process is sort of automated for regular swaps.

It's going to, again, force -- this is 
going to force a potential change to that process. 

We can't rely on the eConfirm, current eConfirm, 

process to get these reps in place. We're going 

to have to long form it so to speak. Yeah, 

those -- those are relatively small burdens so I 

wouldn't -- certainly doesn't -- don't outweigh 

the benefits that the relief provides.

But the risk I noted about, you know, 

making sure that we can rely on a rep, that the 

counterparty is a utility special entity I think 

would be the most important one for us as we -- as 

we look to potentially engage in these 

transactions.

MR. JESKE: I would also add that the 

no action turning into a rule I think is a 

wonderful development. It does particularly 

focus on a couple asset classes. I think that 

might need to be expanded.

Certainly many generation relies on 

coal, fuel oil, and I think the focus on natural 

gas as an input is certainly helpful, but it may 

need to be expanded. If a utility is going to 

make a rep that they are receiving inputs to 

generate power, that should be, you know, pretty 
broad I would hope.

To me -- I think Randy was mentioning 

there's some -- you don't know when the water is 

going to be there or not and you might have to burn 

other sources of fuel to be able to provide the 

power that's necessary. So I think that might 

need to weigh in as well.

MS. DONDNAVILLE: Well I think in the 

petition we did talk about energy and energy 

related swaps and we talked about essentially any 

fuel for generation. We also talked about 

emissions or environmental attributes, swaps, as 

well as -- energy credit, swaps, or other types 

of swaps that would be directly, again, related 

to the utility operations, would not allow them 

to trade metals, to trade crude oil, different 

crude, or literally anything other than things 

intrinsically related to the operation of the 

utility.

One other thing I wanted to talk briefly 

about. You asked if there were any other sort of 

embedded landmines in this, and not to beat a dead 

horse from this morning, but remember that it's 

utility operations related swaps.
I represent counterparties that

transact with utility special entities, as well 

as utility special entities and that discussion 

about what's a swap and what's a trade option or 

what's a forward with embedded optionality, all 

of which are, I think non swaps, plays into this 

as well because as Lael said, the hurdle, the $25 

million sub threshold was an issue because you 

don't want to go close to that unless you know darn 

well you are -- you want to be a swap dealer. You 

have a choice of the people that you transact 

with, you have a choice of the markets that you 

trade in.

Utility special entities don't have 

that choice. They need these products to hedge 

or mitigate there commercial risks. And for that 

reason, to the extent that utility special 

entities can't enter into long term forward 

contracts with embedded optionality, that raises 

any specter that that transaction is going to be 

treated as a swap. That too restricts their 

ability to hedge their risks.

MR. REMMLER: During the panel, there 

was some mention of core competency in swaps and 
as I mentioned in my opening remarks, special 

entities -- Congress said to treat special 

entities a little bit differently. Here we're 

being asked to treat a particular category of 

special entities basically as non special 

entities for particular types of swaps.

So I was wondering if some of the -- some 

of the representatives of utility special 

entities here, if you could speak to perhaps how 

long you've been using swaps, how frequently you 

use swaps, what you mean when you say it's a core 

competency?

MR. HOWARD: Sir, Randy Howard, LADWP. 

We have been in business for about 100 years right 

now, serving the City of Los Angeles, and I think, 

again, what's the definition of a swap. But I 

mean from the optionality perspective, we've 

probably been utilizing various types of 

optionality from the very beginning.

And again, early in LADWP's history, 

hydro was a big issue, but fuel oil and various 

motors and other things came along the way and so 

you needed to hedge based on potential weather 

issues and potential outages of pieces of 
equipment, unplanned outages.

You have major transmission lines that 

at any point could have a failure and you need to 

have an option for an alternate source and those 

need to be in place ahead of time. You don't wait 

until the event occurs. That's the same with 

planning for droughts and earthquakes.

So I would say it's been a core 

competency from the very beginning to keep the 

reliability high and we -- we see that we have a 

skill set very capable of managing both at risk 

and the hedging operation that goes on.

MR. NAULTY: I've personally been 

involved in the trading market since (inaudible) 

888 came out in 1988, or 1998 and you know, we 

employ people in our power marketing group that 

are experienced traders, most of whom have worked 

in -- for a for profit or for utility 

subsidies -- a subsidiary trading companies.

We've used swaps, fix for float swaps, 

both just outright swaps at different points, 

trading hubs, since the markets offered them. So 

when -- in MISO, that would have been in the 

Midwest -- so that would have been 2003 in PJM it 
would have been before that. I can't remember 

the exact date. Maybe Lael knows.

But ever since they've been available 

we've used them. They also use swaps for day 

ahead versus real time power as well in those RTO 

markets. So we've been doing it for a number of 

years.

MR. TRACY: In California, SMUD has 

really, I would say, one of the demarcations was 

when we went to deregulation. That's 

where -- where SMUD established energy risk 

management as a -- as sort of a corporate goal. 

And I mean we went through the whole energy 

crisis. We did not have a big issue with 

our -- our supply cost.

And it's basically because we were able 

to do hedging while the private utilities were not 

able to do hedging. And I -- it's very well 

developed in our company. We have an executive 

group that basically provides the boundaries 

within which our buyers have to stay. And it's 

basically -- these are matching retail load with 

our OCL obligations.

So I think the term trader is a misnomer 
for us anyway; 95 percent of what our folks do is 

actually just matching up the portfolio of 

resources with our retail load. The only 

trading, so to speak, that they really do is 

probably on a daily or a weekly basis when we 

actually have power plants that aren't fully 

utilized and we sell that into the market or we 

buy some, you know, buy some economy energy.

MR. RUST: So for the energy -- oh, 

sorry. So for the Energy Authority, we do 

represent quite a varied set of clients who had 

been in the business for many years. Our 

corporation itself was started in 1997 as a result 

of third quarter 888889. I have been in the power 

marketing business since that time, almost 18 

years. And the Energy Authority was created to 

manage -- to manage those risks or for our 

clients.

We started off with three original 

clients, three original owners. They developed 

our organization to build those competencies. 

We have a comprehensive risk management policy. 

We identify risks. We control risks and we limit 

risks with those -- with that policy and it's 
certainly something that is -- is the focus of our 

organization.

MS. SCHAEFFER: And I guess I was just 

going to follow up, again, with what I mentioned 

when I spoke earlier. Our system being hydro 

based and the fuel being something that we don't 

have as much control over as other types of fuel 

sources for other utilities, it's been adherent 

in our business from the get go, from 1937, that 

there would have been -- usually what we had done 

in the past certainly were just either long term 

purchase or sale arrangements just to ensure that 

we had sufficient generation available to us when 

we might not expect to have sufficient water and 

or generation.

And just going back, I have a copy, for 

example, of our -- our -- the FY 2013 financial 

report and the annual report and we have the whole 

section that deals with our risk management and 

derivative instruments. We have a -- excuse me, 

Transacting Risk Management Committee that 

helps, again, sets the sideboards on what kinds 

of things folks can do.

Again, you know, we're very careful, 
especially given the nature of the kind of entity 

that we are that definitely there is no 

speculative trading period. It's always meant 

to serve our needs. The trades are not -- the 

traders are not supposed to go out and trade 

because they think the price is good. 

It -- it -- there are more specific criteria that 

is involved.

And again, I said, even just in our 

annual reports, talking about the risk management 

and the -- how we model the different types of risk 

using the Monte Carlo simulations and so on. 

Looking at our credit risk with regards to our 

other customers and, you know, we have also used 

interest rate swaps in the past, those kinds of 

things just to hold variety.

But again, you know, we go out there. 

We make sure we either have the people who have 

that capability and or we seek the advice to make 

sure that we have protected ourselves in the best 

way that we can.

MR. REMMLER: I'd like to ask a 

question about the nature of the counterparties 

that are affected by the rule or have been 
affected. You know, Terry, you mentioned that 

you lost about a third of your regional 

counterparties. In this area we have the 

financial entity, swap dealers, we also have 

entities such as Exelon and Mercuria. Are there 

other types of entities that you have been trading 

with who are -- are counterparties and not just 

Terry, or any of the other members of the 

panelists; just sort of to help fill out our 

understanding of who the counterparties are that 

were affected.

MR. NAULTY: Specifically, you know, 

all of the counterparties that we were enabled 

with that came to us after the sub threshold was 

set, said they would no longer take our name, are 

utility affiliated trading companies, without

exception.

And we're a little unique in that most 

of my colleagues here are, you know, talking about 

balancing their supply portfolio with their 

demand by their customers. We're a seller, 

generally, and so if Exelon wanted to buy power 

from us, they couldn't because we're a special 

entity and we've traditionally been a supplier to 
companies like Exelon, for example.

MR. REMMLER: So -- so in effect are you 

saying that you, yourselves are -- and to some 

degree doing dealing and you're affected by this 

rule, is that --

MR. NAULTY: Well, obviously we have to 

have counterparties to trade with. So by being 

classified as a special entity, that kind of 

tainted us from our ability to be able to monetize 

the value of the excess or the surplus capacity 

and energy that we had.

MR. TRACY: I would add to that because 

we deal a lot with the natural gas to fuel our 

power plants; that some of the oil, gas, physical 

folks are the ones that have dropped trading with 

us.

MS. DONDNAVILLE: I can -- because I 

represent a variety of different counterparties 

to special entities, I can give you general 

categories of -- of types of entities, regional 

gas producers who would ordinarily transact with 

the utility special entities in their region. 

They have shut that down.

A natural gas utility located in the 
Central Northern United States; they do not 

transact with utility special entities. The 

retail group Mid-Atlantic, who used to have 

customers who were electric, retail, 

municipalities, they no longer enter into 

anything that smacks of volumetric optionality 

with utility special entities.

So a whole variety of counterparties in 

different regions of the country have excluded 

that counterparty class because of the $25 

million threshold.

MR. TRACY: I just wanted to add one 

thing. And basically, our remaining 

counterparties are financial firms. And one of 

the, you know, as the enterprise risk person at 

SMUD, I always have to think of all of the bad 

things that could happen. And one of the things 

that would concern me is, you know, there is some 

talk of limiting the ability of banks and 

investment banks from owning physical assets like 

power plants and pipelines and such, and 

obviously if that came to pass under, you know, 

what the -- we would think that a lot of the 

financial companies would drop out of that sector 
of trading at that point.

MR. RUST: So for the Energy Authority, 

the clients that we have lost have included 

utilities, marketers, producers, as well as we 

lost some oil and gas companies in -- in the 

beginning.

MR. HOWARD: For Los Angeles 

Department of Water and Power, some of our 

counterparties that we lost were more natural gas 

producers. We own a number of firm pipeline 

rights so we also own a gas field ourselves in 

Wyoming. So there are other parties, smaller 

players, regional players that determine the risk 

were too high. We also have had a number of EEI 

type of utility counterparties that have 

determined that it's probably just easier not to 

conduct or transact directly with us.

MR. REMMLER: I just wanted to follow 

up on something you mentioned, Terry. You said 

that you're already seeing an effect in the market 

due to the recent no action letter. What have 

people expressed to you in terms of what's changed 

when compared with the previous no action letter 

12.18, to the current action letter? 
What -- what do you think has caused that change? 

And if anyone else has any other thoughts --

MR. NAULTY: I think clearly the answer 

is the no action letter that was issued, since its 

issuance, we've already done a swap with one of 

the counterparties that had previously not traded 

with us. So we -- we have seen at least one of 

our counterparties come back to us. And that 

was, again, because of the regional nature of our 

market, it was -- it was a transaction that made 

sense for them and for us as well. And we were 

effectively excluded from that as a result of the 

previous sub threshold issue.

MS. DONDANVILLE: Can I say that 

different counterparties were concerned about 

different ones of the conditions that were 

included in the prior no action letter. Some 

were very concerned about the requirement to take 

a firm position as to whether or not you were a 

financial entity. That definition as most 

people know is not clear. And the intrusion of 

that definition from another part of the CFTC's 

rulemaking, where it's already been questioned, 

created an ambiguity in the no action letter.
Similarly, there was -- it had to 

be -- the transaction had to hedge the physical 

risk of the utility swap entity of the -- sorry, 

of the utility special entity. The hedging 

physical assets test is in the swap dealer rule. 

Most of the utility special entities not being 

swap dealers haven't come to grips with that rule. 

They could have represented that they were 

hedging or mitigating commercial risk, 50/50, 

because they've read that. They understand 

that. So that was another ambiguity in the 

middle of that no action letter.

Probably the most -- the one I heard the 

most from counterparties who were just saying 

it's easier not to deal with it; is the 

requirement to report yourself to the CFTC.

That you had gone over the 25 million 

during the particular quarter, that you were 

comfortable that you were not a financial entity, 

that you were comfortable that the utility 

special entity was hedging their physical risk, 

that you were comfortable you met all of the 

conditions because if you didn't or you made the 

wrong determination, you were subject to audit 
and potentially having inadvertently tripped 

yourself into registration as a swap dealer.

MR. REMMLER: So just to clarify, the 

issue that group of people was having was 

specifically making the -- essentially notifying 

the CFTC that they were relying on the -- on the 

relief or was it the -- the fact that they had to 

make a representation to that effect?

MS. DONDNAVILLE: No, it's -- it's 

essentially saying I'm relying on the no action 

letter, which means you had better be sure that 

you're comfortable that you have relied on the no 

action letter and I went over the 25 million, with 

this special entity, on this date, with this 

trade. If you made any of those determinations 

wrong and you had reported yourself to the CFTC 

as having been rock solid certain, than you may 

have, in 20/20 regulatory hindsight, had been 

required to register as a swap dealer. Most of 

the counterparties that I spoke to were not ever 

intending to become a registered swap dealer.

They paid attention to making sure that 

they had characterized everything absolutely 

correctly and for one of these transactions, you 
can go over 25 million with one swap, or certainly 

with one long term forward contract with a special 

entity with any type of questionable volumetric 

optionality.

MR. REMMLER: Do you think 

that -- that -- that issue would be somewhat 

addressed if we -- if we were to address the issue 

that Lael read regarding reliance and 

representations?

MS. DONDNAVILLE: The issue that Lael 

raised, which is still a requirement in the March 

21 no action letter, can easily be fixed it seems 

in the rules. The swap dealer rules in many parts 

indicate that the counterparty can rely on a 

representation of their counterparty. And I 

guess I would encourage you to have that type of 

a -- of a requirement there. But bringing back 

the variety of other conditions that were in the 

March -- or in the 12.18 no action letter, I think 

would again, reengage the problems that this 

group experienced with that no action letter.

MR. REMMLER: Let me ask -- with regard 

to the -- I think what I'm hearing you saying with 

regard to the representation is, I think, that the 
letter says that representation can be made but 

it doesn't say anything about the counterparty 

relying on the representation. Is that --

MS. DONDNAVILLE: No it says something 

about a representation can be made in another 

place; that they are hedging or mitigating 

commercial risk. It says if there. It does not 

say it in the -- in the line where it says the 

counterparty is a utility special entity. So if 

you are amending Rule 1.3(ggg)(4), that same 

provision that would allow the counterparty to 

rely on a representation of the utility special 

entity is what Lael is requesting.

MR. REMMLER: As I'm sure you know, 

Patty, a lot of the other rules that talk about 

relying on a representation say you can rely on 

a representation unless of course you have 

knowledge.

MS. DONDNAVILLE: Not a problem.

MR. REMMLER: That's not a problem?

MS. DONDNAVILLE: Not a problem.

MR. REMMLER: Okay; good, good. 

Getting back to the notice issue, there was one 

question that came to my mind. One of our 
concerns is that if we create this special 

category in a rule, the utility special entities 

are still special entities with regard to 

interest rate swaps and other types of swaps that 

are not in your core competency.

And as such, if there are dealers

trading in those areas or in any area, frankly 

with you, it may be difficult for us to 

distinguish which swaps that are being to us 

through the swap data repositories and so forth 

should be counted by the dealers when determining 

whether they need to register or not.

So one thought was to have entities that 

are going to rely on this kind of relief, simply 

notify us that they are relying on the relief, not 

that -- not necessarily get to any specific 

conditions, which I understood was a big concern 

for them. I want to ask the panelists, do you 

think that's a reasonable request, a onetime 

notification?

MS. DONDNAVILLE: If the LEIs are on a 

swap and the LEI for one entity is a utility 

special entity and the LEI for the other entity 

is not, then that data, it would seem, would 
already be in the swap data repository, yes?

MR. REMMLER: But it's possible the 

swap could be something other than the type of 

swap.

MS. DONDNAVILLE: They're always going 

to be in the other commodity asset category, 

right? They're always going to be a 

product -- unique product identifier that would 

identify them as energy related.

MR. REMMLER: I suppose it would depend 

on how specific the unique product identifier is, 

yeah -- yeah. That may be another way to go about 

it; okay. I think that's all we have and I think 

we're right about at the time. I don't know if 

anyone else has any other statements they want to 

make or if not, at this point I think we'll close 

the panel. Thank you very much for your 

attendance, appreciate your coming here.

MR. HOWARD: I want to thank you again; 

just your willingness to hear from the utilities 

and continue this effort on working with us. We 

appreciate it. Thank you.

MR. REMMLER: Thank you.

(Whereupon, the HEARING was 
adjourned.) 

* * * * *
CERTIFICATE OF NOTARY PUBLIC 

DISTRICT OF COLUMBIA 

I, Carleton J. Anderson, III, notary public 

in and for the District of Columbia, do hereby 

certify that the forgoing PROCEEDING was duly 

recorded and thereafter reduced to print under my 

direction; that the witnesses were sworn to tell 

the truth under penalty of perjury; that said 

transcript is a true record of the testimony given 

by witnesses; that I am neither counsel for, 

related to, nor employed by any of the parties to 

the action in which this proceeding was called; 

and, furthermore, that I am not a relative or 

employee of any attorney or counsel employed by the 

parties hereto, nor financially or otherwise 

interested in the outcome of this action.

(Signature and Seal on File)

-----------------------------------

Notary Public, in and for the District of Columbia

My Commission Expires: March 31, 2017