2014

Antero Reports 2012 Results and Delivers Operating Update

DENVER, March 18, 2013 /PRNewswire/ --

2012 Release Highlights:

  • Record annual net production of 334 MMcfe/d, a 37% increase over 2011 including discontinued operations
  • 93% increase in Appalachian net annual production to 239 MMcfe/d in 2012, excluding discontinued operations
  • 73% increase in proved reserves to 4.9 Tcfe, pro forma for the sale of Arkoma and Piceance  properties in 2012
  • All-in finding and development costs averaged $0.64/Mcfe for proved reserve additions from all sources in 2012
  • 94% increase in proved, probable and possible reserves (3P) to 26.1 Tcfe including 1.6 billion barrels of oil and NGLs
  • GAAP net loss of $285 million, adjusted non-GAAP earnings of $113 million including discontinued operations
  • Consolidated EBITDAX of $434 million in 2012, up 28% from 2011 including discontinued operations
  • Current net production is 390 MMcfe/d and an additional 115 MMcfe/d net is constrained or shut-in
  • 15 Antero-operated drilling rigs currently running in Marcellus and Utica Shale core areas
  • Marcellus Shale leasehold has grown to 305,000 net acres and Utica Shale to 88,000 net acres
  • Sherwood I processing plant in Marcellus currently producing 3,000 Bbl/d of NGLs
  • Natural gas hedges increased by 17% to 940 Bcfe through 2018 at $4.91 NYMEX-equivalent

Antero Resources today released its 2012 results. Those financial statements are included in Antero Resources LLC's Annual Report on Form 10-K for the year ended December 31, 2012, which has been filed with the Securities and Exchange Commission.

Recent Developments
On January 30, 2013, Antero announced the private placement of $225 million of additional 6% senior unsecured notes due 2020 priced at 103% of par equating to a yield to call of 5.391%.  Antero received net proceeds of $228 million from the offering, which were used to repay a portion of the outstanding borrowings under its senior secured revolving credit facility.  Pro forma for this issuance, at year-end 2012 Antero would have had a fully undrawn credit facility and $43 million in letters of credit outstanding resulting in $657 million of readily available liquidity based on lender commitments and $1.2 billion of unused borrowing base capacity.

On January 28, 2013, Antero announced that proved reserves at year-end 2012 were 4.9 Tcfe, a 73% increase compared to proved reserves at December 31, 2011, pro forma for the 2012 divestment of Antero's Arkoma Basin and Piceance Basin properties.  Proved, probable and possible reserves (3P) increased by 94% to 26.1 Tcfe.  The 3P reserves were comprised of 21.2 Tcfe in the Marcellus Shale and 5.0 Tcfe in the Utica Shale.  Antero's 3P liquids reserves increased by 170% to 1.6 billion barrels at December 31, 2012, including ethane and other natural gas liquids (NGLs).  All-in finding and development costs for proved reserve additions from all sources including drill bit, acquisitions, leasehold additions and all price and performance revisions averaged $0.64 per Mcfe in 2012 while replacing 2,243% of production from drilling.  Antero's 3-year all-in finding and development costs for proved reserves from all sources through 2012 averaged $0.51 per Mcfe.

Also on January 28, 2013, Antero announced a $1.65 billion capital budget for 2013 including $1.15 billion for drilling and completion, $350 million for the construction of gathering pipelines and facilities in the Appalachian Basin (including $150 million for water-handling infrastructure, primarily in the Marcellus Shale) and $150 million for leasehold.  Approximately 74% of the capital budget is allocated to the Marcellus Shale and the remaining 26% is allocated to the Utica Shale.

Financial Results for 2012
In this release, Antero's results are presented either in accordance with GAAP or in a non-GAAP manner where the results of operations combine the Arkoma and Piceance Basin discontinued operations with the Company's continuing Appalachian operations, in each case as noted preceding such presentation.  Investors should be cautioned that this non-GAAP presentation is not representative of Antero's future operations, which will no longer include Arkoma and Piceance Basin assets and revenues.  See "Non-GAAP Financial Measures" for reconciliation between those two presentations.

Net production for 2012 increased by 37% year over year to 122 Bcfe, including production from the Arkoma and Piceance Basin assets sold in June and December 2012, respectively.  The net production increase was primarily driven by new wells brought on line in the Marcellus Shale.  Net production of 122 Bcfe for the year was comprised of 115 Bcf of natural gas, 955,000 barrels of NGLs and 310,000 barrels of oil.  Net daily production averaged 334 MMcfe/d during 2012, and was comprised of 313 MMcf/d of natural gas (93%), 2,611 Bbl/d of NGLs (5%) and 847 Bbl/d of crude oil (2%).  Excluding the Arkoma and Piceance Basin assets sold during 2012, net production increased 93% from 2011 to 87 Bcfe or 239 MMcfe/d and was comprised of 237 MMcf/d of natural gas (99%), 195 Bbl/d of NGLs (1%) and 52 Bbl/d of crude oil (less than 1%).

(The non-GAAP amounts presented below combine the Arkoma and Piceance Basin discontinued operations with the Company's continuing Appalachian operations.  See "Non-GAAP Financial Measures" for a definition of each of these non-GAAP financial measures and tables that reconcile each of these non-GAAP measures to their most directly comparable GAAP financial measure.)

Non-GAAP adjusted net revenues for 2012 increased 30% to $661 million compared to 2011 (including cash-settled derivatives but excluding unrealized derivative gains and losses and the gain on sale of assets).  Liquids production (NGLs and oil) contributed 15% of Non-GAAP adjusted net revenues before commodity hedges during 2012 compared to 13% in the prior year. 

In 2012, Antero realized natural gas hedging gains of $271 million, or $2.21 per Mcfe.  However, due to the fact that expiring financial hedges are settled and realized on a monthly basis while future non-expiring hedges are marked to market at the end of each quarter, we realized gains on hedges that settled during the year while we recognized a small unrealized loss on future hedges as natural gas prices rose to $3.29/MMBtu at year-end 2012 compared to $3.14/MMBtu at year-end 2011.

Excluding the unrealized loss on commodity derivatives, gains and losses on sale of assets and deferred income tax benefit, adjusted net income, a non-GAAP measure, was $113 million for the year.  Cash flow from operations before changes in working capital, a non-GAAP measure, increased 19% from the prior year to $307 million.  EBITDAX of $434 million for 2012 was 27% higher than the prior-year, primarily due to increased production.  For a reconciliation of adjusted net revenues, adjusted net income, cash flow from operations before changes in working capital and EBITDAX to the nearest comparable GAAP measures, please read "Non-GAAP Financial Measures".

(The GAAP amounts presented below exclude the Arkoma and Piceance Basin discontinued operations from the Company's continuing Appalachian operations.)

GAAP revenues for 2012 increased 7% year over year, to $736 million compared to $691 million in 2011.  GAAP revenues in 2012 include a $291 million gain on sale of a portion of our Marcellus gathering assets.  Realized gains on commodity derivatives were $178 million in 2012 compared to $50 million in 2011.  Unrealized gains on commodity derivatives were $1 million in 2012 compared to $446 million in 2011.  Average natural gas prices before hedges decreased 31% from the prior year to $2.99 per Mcf and average natural gas-equivalent prices before hedges decreased 30% to $3.03 per Mcfe.  Additionally, average realized gas prices including hedges decreased by 8% to $5.05 per Mcf.  Average realized NGL prices for 2012 were $52.07 per barrel and average realized oil prices including hedges decreased by 18% to $80.34 per barrel.  Gas-equivalent prices declined by 7% to $5.08 per Mcfe for 2012, after adjusting for all realized gains on commodity derivatives. 

Antero reported a net loss of $285 million for 2012 on a GAAP basis, including a $291 million gain on sale of assets, a $121 million income tax expense on income from continuing operations and a $510 million net loss from discontinued operations arising from the sale of the Arkoma and Piceance Basin assets.  Cash flow from operations including changes in working capital increased 25% from the prior year to $332 million.  EBITDAX from continuing operations of $285 million for 2012 was 78% higher than the prior-year, primarily due to a 93% increase in Marcellus production.  For a description of EBITDAX, and reconciliation to the nearest comparable GAAP measures, please read "Non-GAAP Financial Measures".

GAAP per unit cash production costs (lease operating, gathering, compression and transportation, and production tax) for 2012 were $1.34 per Mcfe, a 13% increase from the prior year primarily driven by increased costs on firm transportation commitments executed to facilitate future production growth.  Per unit lease operating expenses decreased by 30% to $0.07 per Mcfe due to the addition of new high rate Marcellus wells.  GAAP per unit depreciation, depletion and amortization expense decreased 6% from the prior year to $1.17 per Mcfe, driven by low cost reserve increases.  On a per unit basis, GAAP general and administrative expense for 2012 was $0.52 per Mcfe, a 30% decrease from the prior year.

Fourth Quarter 2012
Net production for the fourth quarter of 2012 increased by 14% year over year to 33 Bcfe, including production from the Piceance Basin assets sold in December 2012.  Net production of 33 Bcfe for the quarter was comprised of 32 Bcf of natural gas, 215,000 barrels of NGLs and 71,000 barrels of oil.  Net daily production averaged 363 MMcfe/d during the fourth quarter of 2012, and was comprised of 344 MMcf/d of natural gas (95%), 2,332 Bbl/d of NGLs (4%) and 768 Bbl/d of crude oil (1%).  Excluding the Arkoma and Piceance Basin assets sold during 2012, net production increased 90% from the fourth quarter of 2011 to 29 Bcfe or 316 MMcfe/d and was comprised of 310 MMcf/d of natural gas (98%), 776 Bbl/d of NGLs (1%) and 123 Bbl/d of crude oil (1%)

(The non-GAAP amounts presented below combine the Arkoma and Piceance Basin operations with the Company's other operations.  See "Non-GAAP Financial Measures" for a definition of each of these non-GAAP financial measures and tables that reconcile each of these non-GAAP measures to their most directly comparable GAAP financial measure.)

Non-GAAP adjusted net revenues for the fourth quarter of 2012 (including cash-settled derivatives but excluding unrealized derivative gains and losses) increased by 12% relative to the fourth quarter of 2011 to $177 million, primarily driven by a 14% increase in net production.  

Excluding the unrealized loss on commodity derivatives, loss on sale of assets and the deferred income tax benefit, adjusted net income, a non-GAAP measure, was $20 million for the fourth quarter 2012.  Driven by a 12% increase in adjusted net revenues, cash flow from operations before changes in working capital, a non-GAAP financial measure, increased by 13% to $91 million.  EBITDAX of $111 million for the fourth quarter of 2012 was 3% higher than the prior-year quarter, primarily due to increased Appalachian production offset by reduced cash flows due to the June 2012 Arkoma Basin asset sale.  For a reconciliation of adjusted net revenues, adjusted net income, cash flow from operations before changes in working capital and EBITDAX to the nearest comparable GAAP measures, please read "Non-GAAP Financial Measures".

(The GAAP amounts presented below exclude the Arkoma and Piceance Basin discontinued operations from the Company's continuing Appalachian operations.)

GAAP revenues for fourth quarter 2012 decreased 40% to $235 million compared to $392 million in the fourth quarter 2011.  GAAP revenues in 2012 included a $90 million unrealized commodity derivative gain compared to a $313 million unrealized commodity derivative gain in the prior year quarter.  Average natural gas prices before hedges decreased 6% from the prior year to $3.61 per Mcf and average natural gas-equivalent prices before hedges decreased 4% to $3.71 per Mcfe.  Additionally, average realized gas prices including hedges decreased by 4% to $4.91 per Mcf.  Average realized NGL prices were $52.07 per barrel, while average realized oil prices including hedges decreased by 10% to $80.18 per barrel.  Gas-equivalent prices declined by 3% to $4.98 per Mcfe for 2012, after adjusting for all realized gains on commodity derivatives.

Reported GAAP earnings resulted in a net loss of $7 million for the fourth quarter 2012, including a $13 million deferred income tax expense and a $92 million net loss from discontinued operations arising from the Piceance Basin asset sale.  Cash flow from operations including changes in working capital increased 58% from the prior year quarter to $107 million.  EBITDAX from continuing operations of $86 million for the fourth quarter 2012 was 67% higher than the prior-year quarter, primarily due to increased production.  For a description of EBITDAX, and reconciliation to the nearest comparable GAAP measures, please read "Non-GAAP Financial Measures".

GAAP per unit cash production costs for the fourth quarter of 2012 were $1.58 per Mcfe, a 44% increase over the prior year quarter and a 6% increase over the previous quarter primarily driven by increased costs on firm transportation commitments.  GAAP per unit depreciation, depletion and amortization expense increased 14% from the fourth quarter of 2011 to $1.27 per Mcfe primarily due to increased depreciation on gathering assets from Antero's Doddridge County infrastructure build-out during the second half of 2012. On a per unit basis, GAAP general and administrative expense for the fourth quarter 2012 was $0.47 per Mcfe, a 37% decrease from the fourth quarter of 2011.

Paul M. Rady, Chairman and CEO, commented "2012 was a transformational year for Antero as we divested our Arkoma and Piceance Basin properties as well as sold a portion of our Marcellus midstream assets for a combined total of $1.2 billion.  That capital was quickly redeployed into the Marcellus Shale where we added 84,000 net acres of leasehold and the Utica Shale where we established our initial position and added 73,000 net acres of leasehold.  Virtually all of the roughly 157,000 net acres of new leasehold was located in the rich gas window of the two plays.  In 2012 our operating team completed 64 Marcellus wells with an average EUR of 11.6 Bcfe and an average lateral length of 7,300 feet, completed our first three Utica wells with strong results, and added 2.0 Tcfe of proved reserves with an all-in finding and development cost of $0.64/Mcfe for the year."

Glen Warren, President and CFO, added "Our 93% net production growth in the Marcellus in 2012 illustrates the execution capability of our team as well as the growth potential of this play.  The combination of growing liquids production, a large long-term natural gas hedge position and low finding and development costs should lead to sustainable, profitable growth for Antero for years to come."

Antero Operations
All operational figures are as of the date of the release unless otherwise noted.

Antero's current gross operated production is 487 MMcf/d and estimated net production is 390 MMcfe/d, including 2,500 Bbl/d of NGLs and 175 Bbl/d of oil.  Virtually all of the Company's production is from 135 Antero-operated horizontal Marcellus wells.  Antero has an additional estimated 115 MMcfe/d of net production in the Marcellus and Utica Shales associated with seven new horizontal wells that are shut-in waiting on infrastructure and a number of producing wells that are constrained and waiting on pipeline, compression or processing facilities.   During the fourth quarter of 2012, Antero completed 13 gross operated wells (13 net wells) and currently has 50 gross operated wells (48 net wells) in various stages of drilling, completion or waiting on completion.

Marcellus Shale — Antero is operating 13 drilling rigs in the southwestern core of the Marcellus Shale play, including two shallow rigs, all of which are drilling in northern West Virginia.  The Company plans to add an additional big drilling rig in May 2013.  Antero has 485 MMcf/d of gross operated production in the play virtually all of which is coming from 135 horizontal Marcellus Shale wells, resulting in 389 MMcf/d of net production.  The 389 MMcfe/d net is comprised of approximately 374 MMcf/d of tailgate gas, 2,500 Bbl/d of NGLs and 100 Bbl/d of condensate.  Antero has 31 horizontal wells either in the process of completing or waiting on completion and has three fully-dedicated frac crews currently working in West Virginia along with several spot frac crews as needed.   The 135 horizontal Marcellus wells that Antero has completed and placed on line to date have an average 24-hour peak rate of 13.8 MMcf/d, an average EUR of 10.5 Bcfe assuming ethane rejection and an average lateral length of 6,956 feet.

Antero previously announced the completion of the MarkWest Energy Partners, L.P. (MarkWest) owned and operated Sherwood I cryogenic processing plant located in Doddridge County, West Virginia.  Sherwood I is currently operating in ethane rejection mode and recovering approximately 3,000 Bbl/d gross of propane and heavier products.  Antero has committed to a second 200 MMcf/d gas processing plant, Sherwood II, which is under construction and is located on the same site as Sherwood I.  Sherwood II is expected to go in service in the second quarter of 2013.  Antero has also committed to a third 200 MMcf/d gas processing plant, Sherwood III, which is expected to go on line early in the fourth quarter of 2013, giving Antero access to a total of 600 MMcf/d of Marcellus gas processing capacity by the end of 2013.

Antero recently completed compression facilities located in Ritchie County that add 50 MMcf/d of compression capacity and will connect our first Ritchie County wells to the Sherwood processing facilities.  Additionally, Antero has signed agreements with various third parties to provide compression in central and eastern Doddridge County that will add a combined total of 360 MMcf/d of incremental capacity during the course of 2013.  This additional capacity is expected to relieve an estimated 90 MMcfe/d of currently constrained Marcellus production by the end of third quarter 2013.

Antero has completed the White Oak lateral, a 20-mile high pressure pipeline, which will transport rich gas production from western Doddridge and eastern Ritchie Counties to the Sherwood processing facilities.  Additionally, a high pressure lateral located in eastern Doddridge County was completed by a third party allowing Antero to transport rich gas production from western Harrison County to the Sherwood processing facilities.

The Antero-built Canton low pressure lateral is in service and currently delivering rich gas to Sherwood I.  Antero is planning the construction of a low pressure gathering line connecting third party compression located in central Doddridge County to the Sherwood processing facilities to allow for incremental rich gas gathering capacity. This low pressure pipeline, expected to go into service in the fourth quarter of 2013, is ultimately expected to be converted to a high pressure gathering line serving central Doddridge County.  Additionally, Antero is constructing a 16" low pressure gathering line in Ritchie and Tyler Counties to further expand our gathering infrastructure into higher-BTU areas to allow for delivery of highly rich gas to the Sherwood processing facility.  This line is expected to go in service by the third quarter of 2013.

Antero has 305,000 net acres in the Marcellus Shale play of which only 20% was associated with proved reserves at year-end 2012.  Approximately 80% of Antero's Marcellus leasehold contains processable rich gas.

Utica Shale — Antero is currently operating two drilling rigs in the rich gas/condensate window of the southern core of the Utica Shale play in Ohio.  In December 2012, Antero placed its first well on line which is currently producing to sales and has an additional 25 MMcfe/d of net production that is shut-in waiting on infrastructure associated with the two remaining wells completed during 2012.  In total, Antero has completed three horizontal wells in the Utica play, and has drilled an additional four wells, three of which are currently being completed.  The three wells that are currently being completed are drilled on one pad and are the Company's first increased density pilot in the Utica.

Antero has an agreement with MarkWest to provide processing, fractionation and NGL marketing services in the liquids rich/condensate window of the Utica Shale play.  As a result, MarkWest is currently constructing the Seneca processing complex in Noble County, Ohio to process Antero's rich gas production.  Seneca I, a 200 MMcf/d cryogenic gas processing facility, is expected to begin operations by early fourth quarter 2013.  The processing agreement provides for the construction of an additional 200 MMcf/d facility, Seneca II, which is expected to be installed in the fourth quarter 2013. 

Additionally, MarkWest is building a high pressure lateral connecting the Seneca complex to its existing Cadiz processing complex in Harrison County, Ohio in order to provide Antero preferred access to 185 MMcf/d of combined refrigeration and cryogenic natural gas processing capacity.  This lateral is expected to be on line by the end of the second quarter 2013.  Antero is an anchor producer and will have up to 50 MMcf/d of preferred processing capacity at Cadiz as well as sufficient interruptible overflow capacity until Seneca I becomes operational.  Antero plans to place several additional wells on line late in the second quarter of 2013 when the Cadiz processing capacity becomes available.  Antero is in the process of laying both low and high pressure gathering pipeline to transport its initial Utica production to connect with the MarkWest high pressure lateral to the Cadiz processing complex and eventually to the Seneca processing complex. 

Antero has signed a compression and condensate stabilization agreement with a third party to provide and operate two compressor stations in Noble and Monroe Counties with a combined capacity of 200 MMcf/d as well as two condensate stabilization facilities with a combined capacity of 7,000 Bbl/d, all of which are fully dedicated to Antero.  The compressor stations and condensate stabilization facilities are expected to start up late in the third quarter of 2013.

Antero has assembled over 88,000 net acres of leasehold in the southern core of the Utica Shale play of eastern Ohio.  Almost all of the acreage is believed to be located in the rich gas/condensate window.

Commodity Hedge Update
Antero has hedged 940 Bcfe of future production using fixed price swaps covering the period from January 1, 2013 through December 2018 at an average NYMEX‑equivalent price of $4.91 per MMBtu.  Over 75% of Antero's estimated 2013 natural gas production is hedged at a NYMEX‑equivalent price of $4.78 per MMBtu.  Approximately 20% of Antero's financial hedges are NYMEX hedges and 80% are tied to the Appalachian basin. For the NYMEX hedges, Antero physically delivers its hedged gas through backhaul firm transportation to Henry Hub, the index for NYMEX pricing, which eliminates basis risk on these NYMEX hedges. For presentation purposes, basin prices are converted by Antero to NYMEX‑equivalent prices using current basis differentials in the over-the-counter futures market.  Antero has 11 different counterparties to its hedge contracts, all but one of which are lenders under Antero's bank credit facility.

The following table summarizes Antero's hedge positions held as of today:



Natural gas equivalent


NYMEX-

Equivalent

Calendar Year


MMBtu/day


index price

2013


374,020


$4.78

2014


370,000


$5.23

2015


390,000


$5.40

2016


522,500


$5.02

2017


500,000


$4.40

2018


420,000


$4.79

Non-GAAP Financial Measures
The table below reconciles the Company's GAAP results from continuing operations to Non-GAAP results including operations of the Arkoma Basin assets (prior to the sale) and the loss on the sale.  Antero is including this presentation in order to more clearly illustrate its results of operations during the period:

ANTERO RESOURCES LLC

Statements of Operations and Additional Data

Based on GAAP reported earnings with additional

Details of items included in each line in Form 10-K














Year Ended December 31, 2011


Year Ended December 31, 2012







Total


Including




Total


Including





As


Discontinued


Discontinued


As


Discontinued


Discontinued





Reported


Operations


Operations


Reported


Operations


Operations




(in thousands, except per unit and production data)



Operating revenues:














Natural gas sales

$

195,116


146,718


341,834


259,743


70,602


330,345


NGL sales



34,718


34,718


3,719


31,064


34,783


Oil sales


173


15,269


15,442


1,520


23,730


25,250


Realized commodity derivative gains


49,944


66,654


116,598


178,491


92,166


270,657


Unrealized commodity derivative gains


446,120


113,476


559,596


1,055


(45,808)


(44,753)


Gain on sale of assets





291,190



291,190



Total operating revenues


691,353


376,835


1,068,188


735,718


171,754


907,472

Operating expenses:














Lease operating expenses


4,608


26,037


30,645


6,243


19,901


26,144


Gathering, compression and transportation


37,315


50,453


87,768


91,094


45,089


136,183


Production taxes


11,915


6,307


18,222


20,210


2,967


23,177


Exploration expenses


4,034


5,842


9,876


14,675


664


15,339


Impairment of unproved properties


4,664


6,387


11,051


12,070


962


13,032


Depletion, depreciation and amortization


55,716


114,805


170,521


102,026


88,720


190,746


Accretion of asset retirement obligations


76


359


435


101


404


505


General and administrative


33,342



33,342


45,284



45,284


Loss on sale of compressor station


8,700



8,700






Total operating expenses


160,370


210,190


370,560


291,703


158,707


450,410



Operating income


530,983


166,645


697,628


444,015


13,047


457,062

Interest expense and loss on interest rate derivatives


(74,498)



(74,498)


(97,510)



(97,510)

Loss on sale of discontinued operations






(795,945)


(795,945)



Income (loss) before income taxes


456,485


166,645


623,130


346,505


(782,898)


(436,393)

Income tax benefit (expense)


(185,297)


(45,155)


(230,452)


(121,229)


272,553


151,324

Income from operations


271,188


121,490


392,678


225,276


(510,345)


(285,069)
















Income (loss) from discontinued operations and sale














of discontinued operations


121,490


(121,490)



(510,345)


510,345




Net income (loss) attributable to Antero members

$

392,678



392,678


(285,069)



(285,069)
















Production data:













Natural gas (Bcf)


45


39


84


87


28


115

NGLs (MBbl)


0


708


708


71


884


955

Oil (MBbl)


2


189


191


19


291


310

Combined (Bcfe)


45


44


89


87


35


122

Daily combined production (MMcfe/d)


124


120


244


239


95


334

Average prices before effects of hedges:














Natural gas (per Mcf)

$

4.33

$

3.79

$

4.08

$

2.99

$

2.55

$

2.88


NGLs (per Bbl)

$

$

49.04

$

49.03

$

52.07

$

35.13

$

36.41


Oil (per Bbl)

$

97.19

$

80.79

$

80.98

$

80.34

$

81.55

$

81.48


Combined (per Mcfe)

$

4.33

$

4.46

$

4.40

$

3.03

$

3.61

$

3.20

Average realized prices after effects of hedges:














Natural gas (per Mcf)

$

5.44

$

5.53

$

5.48

$

5.05

$

5.89

$

5.25


NGLs (per Bbl)

$

$

49.04

$

49.03

$

52.07

$

35.13

$

36.41


Oil (per Bbl)

$

97.19

$

77.08

$

77.30

$

80.34

$

80.05

$

80.07


Combined (per Mcfe)

$

5.44

$

5.98

$

5.71

$

5.08

$

6.26

$

5.41

Average Costs (per Mcfe):














Lease operating costs

$

0.10

$

0.59

$

0.34

$

0.07

$

0.57

$

0.21


Gathering, compression, and transportation

$

0.83

$

1.14

$

0.98

$

1.04

$

1.30

$

1.11


Production taxes

$

0.26

$

0.14

$

0.20

$

0.23

$

0.09

$

0.19


Depletion, depreciation, amortization and accretion

$

1.24

$

2.61

$

1.91

$

1.17

$

2.56

$

1.57


General and administrative

$

0.74

$

$

0.37

$

0.52

$

$

0.37







ANTERO RESOURCES LLC

Statements of Operations and Additional Data

Based on GAAP reported earnings with additional

Details of items included in each line in Form 10-K














Three Months Ended December 31, 2011


Three Months Ended December 31, 2012







Total


Including




Total


Including





As


Discontinued


Discontinued


As


Discontinued


Discontinued





Reported


Operations


Operations


Reported


Operations


Operations




(in thousands, except per unit and production data)

Operating revenues:














Natural gas sales

$

58,872


39,440


98,312


103,125


11,296


114,421


NGL sales



12,653


12,653


3,719


4,455


8,174


Oil sales


15


5,136


5,151


910


4,548


5,458


Realized commodity derivative gains


19,713


23,098


42,811


36,985


12,430


49,415


Unrealized commodity derivative gains


313,001


85,851


398,852


90,351


(12,430)


77,921


Gain on sale of assets









Total operating revenues


391,601


166,178


557,779


235,090


20,299


255,389

Operating expenses:














Lease operating expenses


1,098


6,991


8,089


2,171


3,507


5,678


Gathering, compression and transportation


12,364


15,932


28,296


34,149


6,879


41,028


Production taxes


3,564


2,071


5,635


9,476


(1,907)


7,569


Exploration expenses


1,491


1,847


3,338


6,763


155


6,918


Impairment of unproved properties


1,670


1,447


3,117


8,051



8,051


Depletion, depreciation and amortization


17,270


35,986


53,256


36,737


11,375


48,112


Accretion of asset retirement obligations


21


98


119


30


95


125


General and administrative


11,370



11,370


13,700



13,700


Loss on sale of compressor station









Total operating expenses


48,848


64,372


113,220


111,077


20,104


131,181



Operating income


342,753


101,806


444,559


124,013


195


124,208

Interest expense and loss on interest rate derivatives


(23,136)



(23,136)


(26,464)



(26,464)

Loss on sale of discontinued operations






(368,713)


(368,713)



Income (loss) before income taxes


319,617


101,806


421,423


97,549


(368,518)


(270,969)

Income tax benefit (expense)


(130,245)


(25,266)


(155,511)


(12,704)


276,638


263,934

Income from operations


189,372


76,540


265,912


84,845


(91,880)


(7,035)

Income (loss) from discontinued operations and sale














of discontinued operations


76,540


(76,540)



(91,880)


91,880




Net income (loss) attributable to Antero members

$

265,912



265,912


(7,035)



(7,035)
















Production data:













Natural gas (Bcf)


15


12


27


29


3


32

NGLs (MBbl)



248


248


71


143


215

Oil (MBbl)



62


62


11


59


71

Combined (Bcfe)


15


14


29


29


4


33

Daily combined production (MMcfe/d)


167


120


287


316


47


363

Average prices before effects of hedges:














Natural gas (per Mcf)

$

3.83

$

3.31

$

3.60

$

3.61

$

3.60

$

3.61


NGLs (per Bbl)

$

$

51.02

$

51.02

$

52.07

$

31.13

$

38.10


Oil (per Bbl)

$

88.24

$

82.84

$

83.08

$

80.18

$

76.73

$

77.29


Combined (per Mcfe)

$

3.83

$

4.16

$

3.99

$

3.71

$

4.67

$

3.83

Average realized prices after effects of hedges:














Natural gas (per Mcf)

$

5.11

$

5.27

$

3.61

$

4.91

$

7.55

$

5.17


NGLs (per Bbl)

$

$

51.02

$

51.02

$

52.07

$

31.13

$

38.10


Oil (per Bbl)

$

88.24

$

80.48

$

80.73

$

80.18

$

77.66

$

78.07


Combined (per Mcfe)

$

5.11

$

5.84

$

5.45

$

4.98

$

7.52

$

5.31

Average Costs (per Mcfe):














Lease operating costs

$

0.07

$

0.51

$

0.28

$

0.07

$

0.81

$

0.17


Gathering, compression, and transportation

$

0.80

$

1.16

$

0.97

$

1.18

$

1.58

$

1.23


Production taxes

$

0.23

$

0.15

$

0.19

$

0.33

$

-0.44

$

0.23


Depletion, depreciation, amortization and accretion

$

1.12

$

2.62

$

1.83

$

1.27

$

2.64

$

1.44


General and administrative

$

0.74

$

$

0.39

$

0.47

$

$

0.41

Adjusted net revenue as set forth in this release represents total operating revenues adjusted for certain non-cash items including unrealized derivative gains and losses and gains and losses on asset sales.  We believe that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net revenue is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenues as an indicator of financial performance.  The following table reconciles total operating revenues to total adjusted net revenues:



Three months ended

December 31,


Twelve months ended

December 31,




2012


2011


2012


2011












Total revenues from continuing operations


$

235,090


$

391,601


$

735,718


$

691,353


Total revenues from discontinued operations



20,299



166,178



171,754



376,835


Total revenues


$

255,389


$

557,779


$

907,472


$

1,068,188


(Gain) loss on sale of assets




(291,190)



Unrealized commodity derivative (gains) losses


(77,921)


(398,852)


44,753


(559,596)


Adjusted net revenues


$

177,468


$

158,927


$

661,035


$

508,592


Adjusted net income as set forth in this release represents income from operations before deferred income taxes, adjusted for certain non-cash items from operations and discontinued operations.  We believe that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net income is not a measure of financial performance in accordance with GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance.  The following table reconciles income from operations to adjusted net income:



Three months ended

December 31,


Twelve months ended

December 31,




2012


2011


2012


2011












Net income (loss)


$

(7,035)


$

265,912


$

(285,069)


$

392,678


Unrealized commodity derivative (gains) losses


(77,921)


(398,852)


44,753


(559,596)


(Gain) loss on sale of assets


368,713



504,755


(8,700)


Income tax expense (benefit)


(263,934)


155,511


(151,324)


230,452


Adjusted net income


$

19,823


$

22,574


$

113,115


$

54,834


Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operations before changes in working capital. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity. The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release:



Three months ended

December 31,


Twelve months ended

December 31,




2012


2011


2012


2011












Net cash provided by operating activities


$

106,855


$

67,861


$

332,255


$

266,307


Net change in working capital


(15,377)


13,398


(24,877)


(8,309)


Cash flow from operations before changes in working capital


$

91,478


$

81,259


$

307,368


$

257,998


EBITDAX is a non-GAAP financial measure that we define as net income before interest expense and other income or expense, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized hedge gains or losses, gain or loss on sale of assets, franchise taxes and expenses related to business acquisitions.  EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDAX does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our operating performance because this measure is widely used by investors in the natural gas and oil industry to measure a company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under our senior secured revolving credit facility.  EBITDAX is also used as a measure of operating performance pursuant to a covenant under the indenture governing our 9.375%, 7.25% and 6.00% senior notes.

There are significant limitations to using EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDAX reported by different companies. The following table represents a reconciliation of our net income to EBITDAX for the three and twelve months ended December 31, 2011 and 2012:



Three months ended

December 31,


Twelve months ended

December 31,




2012


2011


2012


2011


Net income (loss)


$

84,845


$

189,372


$

225,276


$

271,188


Unrealized loss (gain) on commodity derivative contracts


(90,351)


(313,001)


(1,055)


(446,120)


Interest expense and other


26,464


23,136


97,510


74,498


Provision (benefit) for income taxes


12,704


130,245


121,229


185,297


Depreciation, depletion, amortization and accretion


36,767


17,291


102,127


55,792


Impairment of unproved properties


8,051


1,670


12,070


4,664


Exploration expense


6,763


1,491


14,675


4,304


(Gain) loss on sale of assets




(291,190)


8,700


Other


1,076


1,498


4,068


2,206


EBITDAX from continuing operations


$

86,319


$

51,702


$

284,710


$

160,259
















EBITDAX from discontinued operations



24,252



55,333



149,605



180,562
















EBITDAX


$

110,571


$

107,035


$

434,315


$

340,821


The cash prices realized for oil, NGLs and natural gas production including the amounts realized on cash settled derivatives are a critical component in the Company's performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the income statement.

Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and liquids-rich natural gas properties primarily located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our website is located at www.anteroresources.com.

This release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2012.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms. We use certain terms in this news release, such as "unproved properties" and similar terms that the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2012. 

 

ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2011 and 2012

(In thousands)









2011


2012


Assets






Current assets:






Cash and cash equivalents


$

3,343


18,989


Accounts receivable — trade, net of allowance for doubtful accounts of $182 and $174 in 2011 and 2012, respectively


25,117


21,296


Notes receivable — short-term portion


7,000


4,555


Accrued revenue


35,986


46,669


Derivative instruments


248,550


160,579


Other


13,646


22,518


Total current assets


333,642


274,606


Property and equipment:






Natural gas properties, at cost (successful efforts method):






Unproved properties


834,255


1,243,237


Producing properties


2,497,306


1,689,132


Gathering systems and facilities


142,241


168,930


Other property and equipment


8,314


9,517




3,482,116


3,110,816


Less accumulated depletion, depreciation, and amortization


(601,702)


(173,343)


Property and equipment, net


2,880,414


2,937,473


Derivative instruments


541,423


371,436


Notes receivable — long-term portion


5,111


2,667


Other assets, net


28,210


32,611


Total assets


$

3,788,800


3,618,793


Liabilities and Equity






Current liabilities:






Accounts payable


$

107,027


181,478


Accrued liabilities


37,955


61,161


Revenue distributions payable


34,768


46,037


Current portion of long-term debt



25,000


Deferred income tax liability


75,308


62,620


Total current liabilities


255,058


376,296


Long-term liabilities:






Long-term debt


1,317,330


1,444,058


Deferred income tax liability


245,327


91,692


Other long-term liabilities


12,279


33,010


Total liabilities


1,829,994


1,945,056


Equity:






Members' equity


1,460,947


1,460,947


Accumulated earnings


497,859


212,790


Total equity


1,958,806


1,673,737


Total liabilities and equity


$

3,788,800


3,618,793


 

ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income (Loss)

Years ended December 31, 2010, 2011 and 2012

(In thousands)

 











2010


2011


2012


Revenue:








Natural gas sales


$

47,392


195,116


259,743


Natural gas liquids sales




3,719


Oil sales


39


173


1,520


Realized and unrealized gains on commodity derivative instruments (including unrealized gains of $62,536, $446,120 and $1,055 in 2010, 2011, and 2012, respectively)


77,599


496,064


179,546


Gain on sale of gathering system




291,190


Total revenue


125,030


691,353


735,718


Operating expenses:








Lease operating expenses


1,158


4,608


6,243


Gathering, compression, and transportation


9,237


37,315


91,094


Production taxes


2,885


11,915


20,210


Exploration expenses


2,350


4,034


14,675


Impairment of unproved properties


6,076


4,664


12,070


Depletion, depreciation, and amortization


18,522


55,716


102,026


Accretion of asset retirement obligations


11


76


101


Expenses related to business acquisition


2,544




General and administrative


21,952


33,342


45,284


Loss on sale of assets



8,700



Total operating expenses


64,735


160,370


291,703


Operating income


60,295


530,983


444,015


Other expense:








Interest expense


(56,463)


(74,404)


(97,510)


Realized and unrealized losses on interest derivative instruments, net (including unrealized gains of $6,875 and $4,212 in 2010 and 2011, respectively)


(2,677)


(94)



Total other expense


(59,140)


(74,498)


(97,510)


Income from continuing operations before income taxes and discontinued operations


1,155


456,485


346,505


Provision for income taxes


(939)


(185,297)


(121,229)


Income from continuing operations


216


271,188


225,276


Discontinued operations:








Income (loss) from results of operations and sale of discontinued operations, net of income tax (expense) benefit of $(29,070), $(45,155), and $272,553 in 2010, 2011, and 2012, respectively


228,412


121,490


(510,345)


Net income (loss) and comprehensive income (loss) attributable to Antero equity owners


$

228,628


392,678


(285,069)


 

ANTERO RESOURCES LLC AND SUBSIDIARIES

 

Consolidated Statements of Cash Flows

Years ended December 31, 2010, 2011, and 2012

(In thousands)

 











2010


2011


2012


Cash flows from operating activities:








Net income (loss)


$

228,628


392,678


(285,069)


Adjustment to reconcile net income (loss) to net cash provided by operating activities:








Depletion, depreciation, amortization, and depletion


18,533


55,792


102,127


Impairment of unproved properties


6,076


4,664


12,070


Unrealized gains on derivative instruments, net


(69,411)


(450,332)


(1,055)


Deferred income tax expense


939


185,297


106,229


(Gain) loss on sale of assets



8,700


(291,190)


Loss (gain) on sale of discontinued operations


(147,559)



795,945


Depletion, depreciation, amortization, impairment of unproved properties, and dry hole expense — discontinued operations


164,993


126,041


90,096


Unrealized (gains) losses on derivative instruments, net — discontinued operations


(108,035)


(113,476)


45,808


Deferred income tax expense (benefit) — discontinued operations


29,070


45,155


(272,553)


Other


5,255


3,479


4,960


Changes in assets and liabilities:








Accounts receivable


(2,306)


3,854


5,511


Accrued revenue


(7,408)


(11,118)


(10,683)


Other current assets


261


(4,528)


(8,882)


Accounts payable


9,779


(1,875)


(2,117)


Accrued liabilities


(2,771)


17,124


14,790


Revenue distributions payable


1,747


4,852


11,268


Other




15,000


Net cash provided by operating activities


127,791


266,307


332,255


Cash flows from investing activities:








Additions to proved properties



(105,405)


(10,254)


Additions to unproved properties


(41,277)


(195,131)


(687,403)


Drilling costs


(299,926)


(527,710)


(839,151)


Additions to gathering systems and facilities


(47,124)


(72,837)


(142,294)


Additions to other property and equipment


(2,647)


(2,339)


(3,447)


(Increase) decrease in notes receivable


(2,000)


(10,111)


4,889


Increase in other assets


(556)


(3,095)


(3,707)


Proceeds from asset sales


258,918


15,379


1,217,876


Net assets of business acquired, net of cash of $170


(96,060)




Net cash used in investing activities


(230,672)


(901,249)


(463,491)


Cash flows from financing activities:








Issuance of senior notes


156,000


400,000


300,000


Borrowings (repayments) on bank credit facility, net


(42,080)


265,000


(148,000)


Payments of deferred financing costs


(10,459)


(6,691)


(5,926)


Distribution to members



(28,859)



Other


(2,261)


(153)


808


Net cash provided by financing activities


101,200


629,297


146,882


Net increase (decrease) in cash and cash equivalents


(1,681)


(5,645)


15,646


Cash and cash equivalents, beginning of period


10,669


8,988


3,343


Cash and cash equivalents, end of period


$

8,988


3,343


18,989


Supplemental disclosure of cash flow information:








Cash paid during the period for interest


$

52,326


59,107


90,122


Supplemental disclosure of noncash investing activities:








Changes in accounts payable for additions to properties, gathering systems and facilities


$

32,028


26,465


72,881


 

OPERATING DATA

The following table sets forth selected operating data for the twelve months period ended December 31, 2011 compared to the twelve months period ended December 31, 2012:

 



Year Ended
December 31,


Amount of
Increase


Percent


(in thousands, except per unit data)


2011


2012


(Decrease)


Change


Operating revenues:










Natural gas sales


$

195,116


$

259,743


$

64,627


33%


NGL sales



3,719


3,719


*


Oil sales


173


1,520


1,347


779%


Realized commodity derivative gains


49,944


178,491


128,547


257%


Unrealized commodity derivative gains


446,120


1,055


(445,065)


(100)%


Gain on sale of Appalachian gathering assets



291,190


291,190


*


Total operating revenues


691,353


735,718


44,365


6%


Operating expenses:










Lease operating expenses


4,608


6,243


1,635


35%


Gathering, compression, and transportation


37,315


91,094


53,779


144%


Production taxes


11,915


20,210


8,295


70%


Exploration


4,034


14,675


10,641


264%


Impairment of unproved properties expense


4,664


12,070


7,406


159%


Depletion, depreciation and amortization


55,716


102,026


46,310


83%


Accretion of asset retirement obligations


76


101


25


33%


General and administrative expense


33,342


45,284


11,942


36%


Loss on sale of compressor station


8,700



(8,700)


*


Total operating expenses


160,370


291,703


131,333


82%


Operating income


530,983


444,015


(86,968)


(16)%


Other income expense:










Interest expense


$

(74,404)


$

(97,510)


$

(23,106)


31%


Realized and unrealized interest rate derivative losses


(94)



94


*


Total other expense


(74,498)


(97,510)


(23,012)


31%


Income before income taxes


456,485


346,505


(109,980)


(24)%


Income taxes expense


(185,297)


(121,229)


(64,068)


(35)%


Income from continuing operations


271,188


225,276


(45,912)


(17)%


Income (loss) from discontinued operations


121,490


(510,345)


(631,835)


*


Net income (loss) attributable to Antero equity owners


$

392,678


$

(285,069)


$

(677,747)


(173)%












EBITDAX


$

340,821


$

434,312


$

93,491


27%












Production data:










Natural gas (Bcf)


45


87


42


93%


NGLs (MBbl)



71


71


*


Oil (MBbl)


2


19


17


963%


Combined (Bcfe)


45


87


42


93%


Daily combined production (MMcfe/d)


124


239


115


93%


Average prices before effects of hedges :










Natural gas (per Mcf)


$

4.33


2.99


(1.34)


(31)%


NGLs (per Bbl)


$


52.07


52.07


*


Oil (per Bbl)


$

97.19


80.34


(16.85)


(17)%


Combined (per Mcfe)


$

4.33


3.03


(1.30)


(30)%


Average realized prices after-effects of hedges :










Natural gas (per Mcf)


$

5.44


5.05


(0.39)


(7)%


NGLs (per Bbl)


$


52.07


52.07


*


Oil (per Bbl)


$

97.19


80.34


(16.85)


(17)%


Combined (per Mcfe)


$

5.44


5.08


(0.36)


(7)%


Average costs (per Mcfe):










Lease operating costs


$

0.10


0.07


(0.03)


(30)%


Gathering compression and transportation


$

0.83


1.04


0.21


25%


Production taxes


$

0.26


0.23


(0.03)


(12)%


Depletion depreciation amortization and accretion


$

1.24


1.17


(0.07)


(6)%


General and administrative


$

0.74


0.52


(0.22)


(30)%


SOURCE Antero Resources



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