At September 30, 2012

Three months
ended
September 30,
2012

Proved
reserves
(Bcfe)(1)(2)

PV-10
(in millions)(1)(3)

Net
proved
developed
wells(4)

Total net
acres(5)

Gross
potential
drilling
locations(6)

Average daily
net production
(MMcfe/d)

Appalachian Basin:

Marcellus Shale

3,687

$

1,651

142

271,248

2,850

248

Upper Devonian

10

$

10

2

—

1,000

—

Utica Shale(7)

95

$

202

—

51,701

400

—

Piceance Basin(8)

1,159

$

378

249

61,378

1,400

60

Total

4,951

$

2,241

393

384,327

5,650

308

(1)

Based on internally-prepared reserve estimates, which have not been reviewed or audited by our independent reserve engineers.

(2)

Estimated proved reserve volumes and values for our Appalachian Basin and Piceance Basin properties were calculated using the unweighted twelve-month average of the first-day-of-the-month reference prices for the period ended September 30, 2012, which were $3.00 per Mcfe for the Appalachian Basin and $2.64 per Mcfe for the Piceance Basin properties.

(3)

PV-10 is a non-GAAP financial measure.

(4)

Net producing Marcellus wells are comprised of 95 horizontal wells and 49 vertical wells.

(5)

All net acres allocable to the Upper Devonian are included among the net acres allocated to the Marcellus Shale because the Upper Devonian and the Marcellus Shale are multi-horizon shale formations attributable to the same leases.

(6)

A majority of these potential locations have not been scheduled or identified by management as part of our future multi-year drilling schedule and may not ultimately be completed to the extent we have insufficient resources to do so. We will be required to generate or raise significant capital to conduct such drilling activities. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves.

(7)

Utica reserves are included on the basis of a gas processing agreement that became effective on October 30, 2012, subsequent to the effective date of the reserves estimates.

(8)

On November 1, 2012, we entered into an agreement to sell all of our Piceance Basin assets.

At September 30, 2012(1)

Estimated proved reserves:

Natural gas (Bcf)

3,676

Oil (MMBbl)

17

Natural gas liquids (MMBbl)(2)

195

Total estimated proved reserves (Bcfe)

4,951

Proved developed producing (Bcfe)

861

Proved developed non-producing (Bcfe)

143

Proved undeveloped (Bcfe)

3,947

Percent developed

20

%

PV-10 (in millions)(3)

$

2,241

(1)

Includes our Piceance Basin assets, which we entered into an agreement to sell in November 2012. As of June 30 and September 30, 2012, our Piceance Basin assets contained an estimated 1,146 Bcfe and 1,159 Bcfe of total proved reserves, respectively.

(2)

We elected to begin reporting natural gas liquids (NGLs) separately from natural gas, beginning with our estimated proved reserves for the year ended December 31, 2010. Due to the execution of a gas processing agreement for our Piceance gas production in December 2010, we believe that separate disclosure of NGLs provides more transparency to our production and reserve reporting. Prior to the execution of this agreement in December 2010, NGLs were an immaterial component of our reserves. At December 31, 2011, 78% of our proved reserves by volume were natural gas, 20% were liquids, and 2% were crude oil. At December 31, 2010, 79% of our proved reserves by volume were natural gas, 19% were NGLs and 2% were crude oil, compared to 99% natural gas and 1% oil as of December 31, 2009 when we did not disclose NGLs separately. NGLs for the Arkoma Basin at December 31, 2009 were included in reported natural gas volumes.

Utica reserves of 95 Bcfe equivalent are included in the September 30, 2012 total reserves on the basis of a gas processing agreement that became effective on October 30, 2012, subsequent to period-end.

(3)

PV-10 reflects the present value of our estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization expense, and discounted at 10% per year before income taxes. Estimated proved reserve volumes and values were calculated using the unweighted twelve-month average of the first-day-of-the-month reference prices.

The closest GAAP measure to PV-10, a non-GAAP measure, is the standardized measure of discounted future net cash flows. We believe that the presentation of PV-10 is relevant and useful to our investor as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factor that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV-10 amount is the discounted estimated future income tax. We use PV-10 in our ceiling test computation, and we also compare PV-10 against our debt balances.

July 2011 Pro Forma(1)

November 2012 Pro Forma(1)

Proved Reserves (Bcfe)(2)

1,107

3,792

Proved Developed Reserves (Bcfe)(2)

265

799

3P Reserves (Bcfe)(2)

9,891

22,308

Proved PV-10 ($MMs)(2)(3)

$

1,335

$

2,974

Net Production (MMcfe/d)

138

313

Natural Gas Hedging (Bcfe)

335

749

Bank Commitments ($MMs)(4)

$

750

$

850

Borrowing Base ($MMs)(5)

$

900

$

1,275

Marcellus Net Acreage

189,000

278,000

Utica Net Acreage

—

61,000

(1)

July 2011 and November 2012 reserve and production data adjusted for sale of Arkoma assets on June 29, 2012 and pro forma for Piceance asset sale expected to close in December 2012.

(2)

Internally prepared reserves using SEC reserve methodology and SEC Columbia pricing of $4.29/MMBtu and $3.00/MMBtu as of June 30, 2011 and September 30, 2012, respectively. Excludes Arkoma and Piceance reserves.

(3)

Includes hedge PV-10 of $334 million and $1.1 billion for June 30, 2011 and September 30, 2012, respectively. Excludes Piceance and Arkoma-related hedges.

(4)

Assumes $100 million decrease in current $950 million lender commitments. Antero also anticipates lowering lender commitments to $700 million upon closing the Piceance transaction.

(5)

Assumes $75 million decrease in current $1.65 billion borrowing base pro forma for notes offering and $300 million decrease pro forma for the Piceance divestiture.