Exhibit 99.1

FINAL TRANSCRIPT

Conference Call Transcript

ECT - Q3 2010 ECA MARCELLUS TR I Earnings Conference Call

Event Date/Time: Nov 19, 2010 / 06:00PM  GMT

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CORPORATE PARTICIPANTS

Mike Fletcher

Energy Corporation of America - CFO

John Mork

Energy Corporation of America - CEO and President

CONFERENCE CALL PARTICIPANTS

Dave Zukowski

Citigroup - Analyst

Shawn Radtke

Oppenheimer - Analyst

Scott Ansel

UBS - Analyst

PRESENTATION

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2010 ECA Marcellus Trust I Earnings Conference Call. My name is Michael and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of today’s conference.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today’s conference, Mr. Mike Fletcher, CFO of Energy Corporation of America. You may proceed.

Mike Fletcher  - Energy Corporation of America - CFO

Thank you. Good afternoon, and welcome to the ECA Marcellus Trust I Quarter Three 2010 Conference Call. Energy Corporation of America, which I will refer to as ECA, is the sponsor of the Trust and is responsible for operating the properties in which the Trust has an interest. The following discussion or responses to your questions reflect the views of management of ECA as of today, November 19, 2010 only, and will include forward-looking statements.

Actual results may differ materially. Additional information about risk factors and other factors that could potentially affect the Trust and its financial results is included in the Trust’s press release issued November 5, 2010 and in the Trust’s filings with the SEC, including its most recent quarterly report on Form 10-Q filed on November 12, 2010. As you listen to today’s call, I encourage you to have the Trust press release and Form 10-Q in front of you.

I will now turn the discussion over to John Mork, CEO and President of ECA. John?

John Mork  - Energy Corporation of America - CEO and President

Thank you all for joining us — taking the time to join us today. I look forward to your questions after a short covering of what’s gone on. The overview is, again, pretty straightforward. During the quarters, the wells in the ECA Marcellus Trust performed better than projected. Production exceeded targeted production by just about 16%.

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ECA’s execution of drilling and completing additional wells also went better than planned and I am pleased to report that the ECT quarterly distribution was also above the projected distribution. As a consequence, ECT performed well financially for the quarter ended June 30. Trust revenue was $7.91 million, up 42% quarter-to-quarter. Trust distributable income was $7.42 million, up 55% quarter-to-quarter and ECT’s net cash expenses were approximately $498,000.

The average received price for natural gas in the quarter was $4.89 per Mcf, versus the targeted price of $5.55 per Mcf. The 12% reduction in average price is the result of lower NYMEX prices and higher production volumes. We like higher volumes, but naturally have a lower percentage of a natural gas hedge than originally targeted. The distribution for the quarter ended September 30 is $4 — excuse me, is $0.421 per unit, which exceed the projected distribution by about 1%.

On drilling operations currently ECA is using four drilling rigs in Greene County, two rigs to drill the vertical section and set surface in intermediate casing, and two rigs to drill the horizontal portion of the hole. The rigs are more than sufficient to keep ahead of the drilling schedule and we likely will move one shallow rig and one deep rig away from ECT drilling after the first of the year.

On results to-date, in addition to the 14 producing wells initially in the trust, ECA has completed the drilling of nine proved undeveloped wells — an additional 13 wells are partially drilled. The nine gross wells consist of 8.22 net wells to ECT, with the remaining 0.78 wells owned by other companies with leases adjacent to ECT.

The wells all have lateral lengths longer than the projected Trust lateral of 2,500 feet. The average lateral length for the nine wells was 4,071 feet. The longest lateral was approximately 5,200 feet. Therefore, the Trust is credited with 11.06 net wells for the nine wells drilled.

ECA has drilled seven of the wells longer than 3,500 feet, the maximum Trust footage to count for incremental wells. In essence, the Trust has received an extra 2.38 wells in addition to the 11.06 wells previously mentioned. So net-net, ECA has drilled nine wells, which due to lateral length count as 11.06 wells to the Trust, and ECT has received an extra 2.38 of incremental wells, due to lateral length completed in excess of 3,500 feet.

ECT will receive the production and revenues from these extra wells, even though the well does not count toward the well’s ECA, as required to drill. Today, ECT is receiving approximately 22% more wells than were required in the Trust agreement.

Let me take a minute and explain this. When you drill horizontal wells, obviously the most expensive portion of the well is getting down to the roughly 8,000 feet to the Marcellus and, indeed, the cheapest portion of the well is the horizontal lateral. So it makes economic sense to ECA to extend that lateral even though it is burdened by the one half, 50% interest royalty owing to the Trust. So we make money by drilling these longer, so this is a benefit to the Trust.

Five of the nine wells drilled are fractured and in production. Three wells are scheduled to be fractured and in production in December, and one well is scheduled for fracturing and production in January.

On our operating activity, as of this morning ECT has 19 wells that are fractured. One well is cleaning up after fracturing, and the remaining 18 wells are in production. ECT currently has the original 14 wells producing, 11.06 net wells drilled, 13 wells drilling and an additional eight drilling permits. Therefore, 46 of the required 66 Trust wells are either producing, drilled or permitted. Effectively, the number of ECT wells may be considerably higher as ECA continues to drill laterals longer than 3,500 feet.

Something I would really like to brag about is the Greene County water handling system that I have mentioned before. It is completed and state-of-the-art. The water system saves — and this is a stupendous number — 1,000 truckloads of water per well, or 250,000 ton miles per well that don’t cross those roads in Greene County.

This is a huge win/win. The system is capable of transporting 72,000 gallons per hour of water. We have — we save money doing this and we also save a bunch of wear and tear in the county. So the people in the county love us, and we save money. It’s a great win/win.

The ACN pipeline system in Greene County is nearly ready for full — all future ECT production. An additional compressor is scheduled to go into production today. Actually, in checking with the operating people, it is going into production as we speak, and this will assist us with the incremental production. And we anticipate no production delays due to the infrastructure in this project.

Let me talk just a little about production. For the quarter ended 9/30, the Trust was scheduled to have 14 wells in production and 15 wells were actually in production, but two of those wells were (inaudible) brought into line late in September, so they only produced a few days.

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One completed well was not in production because the production from the other two wells on that drilling pad exceeded the designed capacity for the pipeline surfacing the pad. The projected production for the 14 wells was 1.399 Bcf, and the actual production for the quarter for 13 wells was 1.619, again about 16% above plan.

Current gross production from the 18 wells in line is approximately 38,000 Mcf per day, up 80% from the 21,000 gross Mcf per day reported at our last call. Because of lateral length these would count as 18.5 wells. Targeted net production for the quarter ended 12/31 — the quarter we are in — is 21,500 Mcf per day, and actual net production as of yesterday was approximately 24,500 Mcf per day.

Let me talk a little bit about natural gas — or, natural gas pricing. If the quarter — quarterly NYMEX prices closed yesterday the weighted average price received for the Trust would be $3.70 per MMBtu, or 29% below the projected NYMEX price. With the hedges we have in place the price would be $4.85 per MMBtu, or 7% below natural gas prices. As everybody on this call knows, the gas prices have not been kind to us.

The Trust properties are exceeding projected production levels, which is a good thing, but as a result of higher production a smaller percentage of Trust gas is hedged and the weighted average of price received will actually be slightly lower. The good news is that we are, to-date, farther ahead on production than we are on price, so we are beating targeted distribution numbers.

On regulatory issues, we just simply have nothing to report, but I can tell — and many of you read the things in the press — I am glad that these Trust properties are in a welcoming area and not located in Pittsburgh.

On the severance tax update, again, I would not normally report on potential changes in tax laws, and at this point I can only report on rumors. After the election it appears — now appears much less likely that the severance tax will be passed in this year.

Farther out in the future is more difficult to tell, but it appears that the political environment for natural gas production in Pennsylvania is improving under the change in administrations. We will keep on this, and when we know something we will report. Although we follow this legislative area closely, I probably do not have any better information than anybody else on this call.

That’s all my prepared remarks. I would be glad to answer questions. Thank you.

QUESTION AND ANSWER

Operator

(Operator Instructions)

And your first question comes from the line of Dave Zukowski of Citi. You may proceed.

Dave Zukowski  - Citigroup - Analyst

Hi, guys. Thanks for taking my questions. I was wondering what — if you guys have an expected distance for your horizontal, lateral lengths that are being drilled.

John Mork  - Energy Corporation of America - CEO and President

We are — to answer that, we would like to get the lateral length obviously as long as we can economically. And of late, we have been drilling longer laterals with good success and completing them. That’s the important thing; not just getting long laterals, but successfully completing them.

I know a well we are drilling today, as of this morning, was just a hair past 5,000 feet lateral. So I — we are targeting in that area, but to say that we are absolutely going to do that is not guaranteed.

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Dave Zukowski  - Citigroup - Analyst

Okay. So, definitely the potential is for like a net more than 52 wells.

John Mork  - Energy Corporation of America - CEO and President

Well, right now there has to be a net more than 52 wells. If we drilled every other well exactly 2,500 hundred feet, you would get 52 wells plus 2.38 free wells.

Dave Zukowski  - Citigroup - Analyst

Right. Okay.

John Mork  - Energy Corporation of America - CEO and President

So, it’s above that now. What we — somehow we would not honor, which is no chance of that — our obligation. So, yes, you — if everything just finished at 2,500 feet we would get 54.38 wells today.

Dave Zukowski  - Citigroup - Analyst

Great. Thank you. And then, just one additional question. I was wondering if you would be able to share with us maybe some of your 30-day IP rates for your most recent PDP, or PUD wells.

John Mork  - Energy Corporation of America - CEO and President

Our 30-day IP rates — I don’t have that number in front of me — but have improved, and are slightly over 3,000 Mcf a day.

Dave Zukowski  - Citigroup - Analyst

Okay. And that is for the PUDs and the PDPs?

John Mork  - Energy Corporation of America - CEO and President

That is for the PUD wells.

Dave Zukowski  - Citigroup - Analyst

So, that’s for the PUD wells. Okay. Okay, thank you very much.

Operator

Your next question comes from the line of [Shawn Radtke] of Oppenheimer. You may proceed.

Shawn Radtke  - Oppenheimer - Analyst

Hey, how are you guys doing?

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John Mork  - Energy Corporation of America - CEO and President

Well, thank you.

Shawn Radtke  - Oppenheimer - Analyst

Sort of touching more on the IP 30 rate, as the — as you increase the horizontal length, is that helping boost the IP 30 production rates?

John Mork  - Energy Corporation of America - CEO and President

I — we are doing, quite frankly, a bunch of regression analysis on this and logically we would think that was the case, and I think that is going to be the case. But, there are so many variables going on I would hate to guarantee you that the case, but it seems to be. The longer wells seem to be doing better. But, you have got geology, you have got how you frac them, rates at which you frac them and a number of other things on there. If we were having a beer that’s what I would guess, but there are a lot of things that seem to be improving.

Shawn Radtke  - Oppenheimer - Analyst

Oh, fantastic. And on — then with the production, how are the fade rates — I guess with the earlier wells that you have drilled, how are those holding up?

John Mork  - Energy Corporation of America - CEO and President

The what rates?

Shawn Radtke  - Oppenheimer - Analyst

Just how fast they are producing, or where they are producing now relative to their initial production rates.

John Mork  - Energy Corporation of America - CEO and President

They are doing considerably better than we originally targeted. They are staying with that 40% better rate. The numbers — I can give you a little better numbers; they have brought in here. In the reserve report the IP 30 estimated was 2.2 in Mcf a day, and for the five proved undeveloped locations that we’ve had in line for 30 days, they have averaged 3.1.

Shawn Radtke  - Oppenheimer - Analyst

Okay. But, good quarter. Thanks, guys.

John Mork  - Energy Corporation of America - CEO and President

Thank you.

Operator

(Operator Instructions)

Your next question comes from the line of Scott Ansel of UBS. You may proceed.

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Scott Ansel  - UBS - Analyst

Hi, John. I just wanted to know. You had mentioned that you had hedged the production that you were expecting to get and now that you have more are you going to hedge some of that and, if so, how far?

John Mork  - Energy Corporation of America - CEO and President

Scott, we hedged 50% of the production in swaps and floors that we had anticipated. And we have no plans for hedging additional production, guessing on the market.

Scott Ansel  - UBS - Analyst

Okay. In other words, prices are too low for you to want to lock that in at this point.

John Mork  - Energy Corporation of America - CEO and President

They are, and we — the general idea behind the Trust was once we got — took the risk out of the first four years by hedging gas that it would get the benefits and the liabilities of the market. I can tell you something. Just from an ECA point of view, we have a whole lot of people that work very hard on forecasting gas markets. And if you take our — and we have done very well lately, but if you take ECA’s, not ECT’s history and do a pure look back, we would have been better to have never hedged.

Scott Ansel  - UBS - Analyst

I see. Okay. Thank you.

John Mork  - Energy Corporation of America - CEO and President

You’re welcome.

Operator

And there are no further questions at this time.

John Mork  - Energy Corporation of America - CEO and President

Well, thank you very much, all, for joining in the call today. We look forward to meeting with some or all of you when we do the call for the fourth quarter.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a good day.

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