Exhibit 99.1

FINAL TRANSCRIPT

Conference Call Transcript

ECT - Q2 2010 ECA MARCELLUS TR I Earnings Conference Call

Event Date/Time: Aug 18, 2010 / 06:00PM  GMT

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CORPORATE PARTICIPANTS

Mike Fletcher

Energy Corporation of America - CFO

John Mork

Energy Corporation of America - CEO

CONFERENCE CALL PARTICIPANTS

Kevin Smith

Raymond James - Analyst

Dave Zukowski

Citigroup - Analyst

PRESENTATION

Operator

Good day, ladies and gentlemen, and welcome to the ECA Marcellus Trust I Second Quarter 2010 Earnings Conference Call. My name is Carissa and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today’s call, Mr. Mike Fletcher, Chief Financial Officer of Energy Corporation of America. Please, proceed.

Mike Fletcher  - Energy Corporation of America - CFO

Hello and welcome to the conference call. Energy Corporation of America, which I will refer to as ECA, is the sponsor of the B 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, August 18, 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 press release issued August 5, 2010 and in the trust filings with the SEC including its most recent quarterly report on Form 10-Q filed on August 16, 2010. As you listen to today’s call, I encourage you to have the trusts press release and Form 10-Q in front of you.

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

John Mork  - Energy Corporation of America - CEO

Good afternoon. Thank you for joining us on the initial quarterly conference call for ECT. And we plan to have conference calls quarterly through the drilling period, which will be about the next three years.

Let me give you a brief overview of the trust for the first quarter; it’s pretty straightforward. During the quarter the wells in the ECA Marcellus Trust I performed better than projected. ECA’s execution of drilling and completing additional wells went better than planned, and I am pleased to report that ECT quarterly distribution was 20% above the projected distribution.

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As a consequence, ECT performed well financially for the quarter ended June 30. Press revenue was $5.56 million, which exceeded projected revenue of $4.4 million by $1.16 million. Trust distributable income was $4.79 million, which exceeded the projected income for the quarter of $3.99 million by 20%, and ECA received hedge recoupment of $58,000 as well as an incentive distribution of $58,000 in the first quarter.

ECT expenses were limited to certain initial expenses totaling approximately $660,000. The trustee, Bank of New York and ECA waived their trust overhead charges for the first quarter ending 6/30 totaling $52,500. The distribution for the quarter ended 6/30 is $0.272 per unit and that exceeded the projected distribution by about 20%.

Going into drilling operations, ECA is currently using two drilling rigs in Greene County; one rig to drill the vertical section and set surface to intermediate casing, and ECA is using a larger second rig to drill the horizontal portion of the hole. With the efficiencies gained these rigs are sufficient to keep on or ahead of drilling schedule, but the Company has other rigs under contract which could be added if necessary.

A little on the drilling results, in addition to the 14 producing wells, ECA has completed the drilling of five wells and an additional six wells are partially drilled. The five gross wells consist of 4.22 net wells to ECT with the remaining 0.78 wells owned by other companies which have leases adjacent to the ECT leases.

The wells all had lateral lengths longer than the projected trust lateral of 2,500 feet. The average lateral length was 3,606 feet. The longest lateral was approximately 5,000 feet. Therefore, the trust is credited with 5.46 net wells for the five wells drilled.

ECA has drilled three of the wells longer than the 3,500 feet, the maximum trust footage to count for incremental wells. In essence, the trust received an extra 60% of an incremental well in addition to the 5.46 wells previously mentioned. So net/net ECA has drilled five wells which due to lateral length count as 5.46 wells to the trust and ECT has received an extra six-tenths of an incremental well due to lateral length completed in excess of 3,500 feet.

ECT will receive the production revenue from this extra well even though the well does not count towards the wells ECA is required to drill, therefore ECT will receive production from at least 66.6 equivalent wells rather than the 66 equivalent wells specified in the S-1. Three of the five wells drilled so far are scheduled to be fractured and placed in production in September, and the other two wells are scheduled to be fractured and placed in production in October.

On other activities, as of this morning ECA has fractured 25 of 31 stages on three new wells. If the frac continues as planned it will be completed tomorrow, and the wells should be cleaned up and in production early next week. I wish you could all see this operation — it’s something. There are over 50 individual large pieces of equipment and 50 operating personnel working 24 hours a day since last Friday on this six acre pad, in addition to the three wells on the pad which are already producing.

ECA has accomplished some fabulous efficiency. On average, we are perforating, setting plugs, and pumping large frac jobs continuously at one job at about every five hours — a little less than that, actually. And here are the total volumes pumped for this frac; they’re significant —13 million gallons of water and 11.5 million pounds of sand. ECA currently has an additional 17 drilling permits available for ECT in addition to the six wells currently being drilled, therefore 37.6 of the required 66 trust wells are either producing, drilled, or permitted.

The Greene County water handling system is largely completed. This is a water system built by and for ECA, which greatly reduces road and — potential environmental damage and saves cost — drilling and completion cost, a huge win/win, both for the area, the environment, and ECA. The AC Nielsen pipeline system in Green County is nearly ready for all future ECT gas production and will be completed when the pipeline expansion is completed in September. We anticipate no production delays due to infrastructure.

About production, for the quarter ended 6/30 the trust was scheduled to have eight wells in production, but only seven wells were in production. One completed well was not in production because the production from the other two wells on that drilling pad exceeded the design pipeline capacity for the pipeline servicing the drilling pad. Generally, this is a nice problem to have. ECA is in the process of increasing the pipeline capacity, and expects to have the third well in production in September.

The projected production for the quarter from eight wells was 675,000 Mcf, and the actual production for the quarter from seven wells was 968,000 Mcf, about 43% above plan. In July ten wells were in production, and projected to produce 278,000 Mcf. The actual production is estimated at 460,000 Mcf, or approximately 65% greater than projected.

Current gross production from ten producing wells is 21,000 Mcf per day. The three wells placed in production in July had an average IP30 of 2,617 Mcf per day, or approximately 16% greater than the IP30 projected by Ryder Scott.

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Now, just some comments about natural gas pricing. During the quarter ended 6/30 the projected price was exactly equal to the received price. Obviously, our projecting is not that good. Remember, the quarter had priced before the final projection was made. If the quarterly NYMEX prices closed yesterday rather than when they close later this month, the unweighted average price received would be 5.3% below what was projected for the NYMEX price.

The trust properties are exceeding projected production levels, which is a good thing, but as a result of higher production, a smaller percentage of the trust gas is hedged at the higher swap price of 675 per MMBTU, and therefore the weighted average price received will actually be slightly lower than what was projected.

Now, I’ll comment about regulatory issues. In normal times this would largely complete my report, but it seems that in these times a report on oil and gas operations would be incomplete without a regulatory segment. In its history of operations in Pennsylvania, ECA has had no material incidents or violations. Only one other operator out of the 25 major operators in Pennsylvania has a lower number of violations per well than ECA, as reported by the Pennsylvania Land Trust Association.

Even with this outstanding record, ECA has created three new positions within the Company specifically focused on regulatory compliance in Pennsylvania. Currently, the Company has no, and I repeat, no outstanding incidents or regulatory issues and our plans are to keep our excellent record just as it is.

Well, again, severance tax — I would not normally report on potential changes in tax laws and at this point I can only report rumors, but it appears that the most likely case is for a severance tax to be enacted in the fourth quarter of 2010 and become effective next year. The tax rate most talked about is 5%. Although we follow this legislation area closely, I probably do not have any better information than others on this call, and I might add that my record of forecasting legislative actions is even poorer than my record of forecasting gas prices.

Thank you for listening in. May I take your questions now?

QUESTION AND ANSWER

Operator

(Operator Instructions)

And your first question comes from the line of Kevin Smith of Raymond James. Please, proceed.

Kevin Smith  - Raymond James - Analyst

Hey, good afternoon, gentlemen. Congrats, on the nice quarter.

John Mork  - Energy Corporation of America - CEO

Thank you.

Kevin Smith  - Raymond James - Analyst

It sounds like — well, is what you detailed it, you’re drilling laterals much longer than the 2,500 feet and you’re getting pretty good production. Is there any rhyme or reason that you’re drilling closer to 3,000 foot laterals and is that kind of the pace you expect to continue to go?

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John Mork  - Energy Corporation of America - CEO

Well, Kevin, we really plan to drill longer than 3,000 feet and even longer than 3,500 feet if we can accomplish that. And the reason — the first question would come to my mind is, why would you guys ever drill longer than 3,500 feet? You’re giving part of the well away. It’s a huge win/win. It wins for the trust.

And when we look at our economics, they actually work pretty darn well for us on that half-interest well longer than 3,500 feet, remembering that that’s the cheapest part of any well to drill. The expensive part is getting down to 8,000 feet and once you get going sideways and there aren’t operating problems, that’s the cheap part of the well.

Kevin Smith  - Raymond James - Analyst

Fair enough. And then I guess the next question’s on frac stages. Are you experimenting or changing anything there, or do you feel like you’re — you’ve kind of got what you need as far as what you’re doing on the completion side?

John Mork  - Energy Corporation of America - CEO

The answer is yes to both of those. We think we’ve got what we need, but we’re always trying to improve and we’re always playing with that a little bit, but there aren’t any significant changes. It’s not like we were fracing every 10 feet and we’ve gone to 500 feet or something. It’s just about the same all the time.

Kevin Smith  - Raymond James - Analyst

Okay. That’s pretty much all the questions I have. Thank you.

Operator

(Operator Instructions)

And your next question comes from the line of [Dave Zukowski] of Citigroup. Please, proceed.

Dave Zukowski  - Citigroup - Analyst

Hi. Thanks for taking my question. I was wondering, in terms of natural gas prices, have you guys come up with a breakeven point given your current cost structure?

John Mork  - Energy Corporation of America - CEO

A break-even point for drilling these wells or breakeven point for producing them?

Dave Zukowski  - Citigroup - Analyst

For producing them.

John Mork  - Energy Corporation of America - CEO

It is tiny. I’m not prepared to disclose that, but our breakeven operating cost point is well below — well below $1 in Mcf.

Dave Zukowski  - Citigroup - Analyst

Okay. Thank you very much. That’s all I have.

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Operator

And there are no further questions at this time. I’d like to turn the call back over to management for closing remarks.

John Mork  - Energy Corporation of America - CEO

Well, thank you very much for your questions and for listening in, and I look forward to talking to you about three months from now and we’ll report on the third quarter at that time. And as I mentioned earlier, we will have these calls during the drilling portion. When the drilling is done, we’ll discontinue the calls and let the numbers speak for themselves. Thank you now.

Operator

Ladies and gentlemen, that concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.

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