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Cook Inlet Gas Study 2010
Cook Inlet Gas Study -An Analysis for Meeting the Natural Gas Needs of Cook Inlet Utility Customers prepared for ENSTAREL Natural Gas Company CHUGL <aPOWERINGALASKA'S FUTURE [=porleaRSEVENTY-FIVEYearsMarch 2010 Peter J.Stokes,PE William Grether &Thomas P.Walsh Petrotechnical Resources of Alaska 3601 C Street Suite 822 Anchorage,AK 99503 (907)272-1232 Due to the uncertainties of drilling and producing activities of operating and exploration companies and what Alaska state agencies do and do not do in influencing those activities,this study should be considered a best estimate based on current data.It was prepared using generally accepted engineering and geological predictive methods.As such, Petrotechnical Resources of Alaska can make no warranty as to actual future Cook Inlet gas drilling and production. Executive Summary prepared by Cook Inlet Utilities ENSTAR Natural Gas Company,Chugach Electric Association,and Anchorage Municipal Light and Power (Cook Inlet Utilities)commissioned Petrotechnical Resources of Alaska (PRA)to study Cook Inlet natural gas reserves and forecast annual natural gas production.We asked PRA to estimate the cost of the development necessary to meet the immediate needs of Cook Inlet utility customers from 2010 to 2020.The PRA study includes a review of estimated reserves and deliverability of Cook Inlet gas wells drilled between 2001 and 2009,scenarios for potential development activity,a review of a December 2009 Alaska Department of Natural Resources (DNR)reserves analysis,and an analysis of when it might be necessary to rely on non-Cook Inlet natural gas sources,such as liquefied natural gas (LNG)imports or other in-state resources. In the future,Cook Inlet utility customers should expect to pay more for the gas used by Cook Inlet Utilities to generate heat and electricity.PRA examined results from all of the gas wells drilled in Cook Inlet between 2001 and 2009 and determined that producers spent approximately $1.0 to $1.2 billion in development costs to add reserves of approximately 519 billion cubic feet (Bef)of natural gas.If the current trends for well success rates and costs continue,producers will need to spend two to three times that amount,an estimated $1.9 to $2.8 billion,to meet projected Cook Inlet utility demand from 2010 to 2020.Producers will invest the necessary capital in future drilling activity only if they have a reasonable expectation of a return that is competitive with other investment opportunities.In order to assure continued drilling activities,increased development costs must be reflected in the market price utilities pay for the gas and ultimately pass onto their customers.Cook Inlet Utilities will also require storage services to deliver gas to their customers on the coldest days and enable producers to optimize gas production rates.Theestimatedcostofastoragefacilityis$150 to $200 million'.These storage costs will also be borne by utility customers. 'Storage cost estimates based on ENSTAR's development assessment. 160 140 |-Sn cree ne Dees seni enoneameeeee 120 +-.-_o an -100 bt ws va 80 ;Pian $1.9 to $2.8 billion capital investmentarequiredtoincreasesupplyofgas 60 needed to meet demand from existing and new wells wi pjected 0 D 4 40 'o.0 eS LaeayGgateOrns.dditio production ig20_a0 v 0 .ig tro -ro "TF t TO -mi t T 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year Figure 1 --Cook Inlet Supply &Demand PRA used a decline curve analysis to review the same underlying data analyzed in the 2009 DNR reserves study and reached a similar conclusion regarding when the supply of gas from existingwellswillnotmeetdemand”.The PRA study took the next step,estimating the cost of bringingtheundevelopedgasresourcestomarket',PRA determined that if significant efforts are undertaken to develop gas from the resources identified by DNR and if the current trends in drilling success rates continue,gas might be available through 2020.However,even if an aggressive development effort were undertaken immediately,that effort may fail to bring new gas to market quickly enough to provide needed gas when demand is projected to exceed supply as soon as 2013.Utilities need to plan for an alternative supply to meet their customers'needs. Having undeveloped gas resources in the ground will not enable Cook Inlet Utilities to provide heat and power to their customers.The gas resources will only be developed and brought to market at prices that incentivize the producers to justify their investment.Contracts with these higher prices will require RCA approval. Cook Inlet Utilities need a viable option if additional Cook Inlet development does not materialize.To provide a stable gas supply,non-Cook Inlet sources such as gas delivered from the North Slope or LNG imports,are alternatives that must be pursued.The "easy"gas has been found in the challenging geology of Cook Inlet.The future costs of developing additional reserves will be substantial.As the cost of continued Cook Inlet gas production increases, alternative gas supply sources may become more economically attractive.Regulatory uncertainty has also discouraged Cook Inlet producers from exploring for and developing Cook ?PRA's study estimates remaining reserves of 729 Bef from existing wells,compared with DNR's forecast of 863 Bcf of Proven Developed Producing reserves. >The DNR study did not address the cost of bringing undeveloped resources to the market.(see DNR Study Figure 14 Description) Inlet reserves'.In the current regulatory environment,two of the three major Cook Inlet producers have publicly stated that they intend to drill only to meet current contract obligations. Future development depends on a change in the regulatory climate to one where consistent standards are applied to approve negotiated utility gas supply agreements,even if those agreements reflect the increased costs of resource development. The Cook Inlet market is in transition.Current gas fields are in decline and the loss of industrial customers has reduced the producers'incentives to do anything but meet existing contractual obligations.In order for utilities to be able to continue to supply current customers and to accommodate future growth,Cook Inlet Utilities and others must take action. Immediate Actions Needed: .@)New gas supply agreements between Cook Inlet Utilities and Producers must be signed to ensure continued development of Cook Inlet reserves. There must be predictable timelines and standards for regulatory approval of gas supply agreements.The Regulatory Commission of Alaska must be willing to approve gas supply contracts negotiated at arm's length,even if prices under those contracts increase. Cook Inlet Utilities must develop gas storage to assure deliverability on the coldest days and optimize gas production throughout the year. Cook Inlet Utilities should continue raising customer awareness,conservation efforts,and curtailment plans,to prepare for potential shortfalls. Additional well-capitalized exploration and development companies must commit to develop Cook Inlet and other Alaska gas reserves. To assure certainty of supply,Cook Inlet Utilities must determine how they will bring gas into Cook Inlet within the next five years to ensure the needs of their customers are met.Alternative gas supply sources include LNG imports and North Slope gas delivered by pipeline to south central Alaska. Additional regional industrial gas demand must be found to encourage the development of Cook Inlet reserves and spread the increased costs of production. Land management processes must be streamlined to encourage and accelerate reserve and infrastructure development. *Recent favorable regulatory decisions on utility gas supply agreements may be a positive sign, Technical Summary ENSTAR Natural Gas Company,Chugach Electric Association,and Anchorage Municipal Light and Power (Cook Inlet Utilities)hired Petrotechnical Resources of Alaska (PRA)to perform a study of Cook Inlet reserves and deliverability.The components of the study included: Review the deliverability of Cook Inlet gas wells drilled between 2001 and 2009 Forecast potential deliverability of future drilled gas wells Review Alaska Department of Natural Resources (DNR)reserves analysis Analyze timing of demand for a delivery of potential non-Cook Inlet gas sources,such as liquefied natural gas (LNG)imports or other in-state resources High level findings of the study are: Cook Inlet Well Drilling Results -2001 to 2009 e Drivers for Cook Inlet well drilling between 2001 and 2009 included: o Newly executed gas contracts o Reserves development associated with negotiated gas contracts rejected by the RCA o LNG Exports and License Extensions o Increasing Regional Natural Gas Prices o Industrial Fertilizer Operations e Results for Cook Inlet well drilling between 2001 and 2009: ©128 gas wells were drilled between 2001 and 2009,of which,105 were completed with an average rate of 3.6 MMSCF/D for the first 12 months of production =97 wells were permitted and drilled as Gas Development wells;88 of these were completed as gas wells,for a 90.7%success rate =31 wells were permitted and drilled as Gas Exploration wells;18 were completed as gas wells,for a 58.1%success rate =»Anestimated 519 BCF of gas was developed by these wells "Ninilchik,Kenai and Deep Creek Units had the most drilling activity during this period;Ninilchik was very successful;Kenai wells were average and Deep Creek wells were marginal «The estimated costs for drilling and facilities of these 128 gas wells are between $1.0 and $1.2 billion Review of DNR Analysis of Available Reserves e The DNR completed a Cook Inlet Gas Reserves Study in December 2009 e Inthe DNR study,reserves and resources are systematically estimated,but as stated in the report,the timing of the development of undeveloped reserves is only an estimate as shown in DNR's Figure 14,a "Hypothetical production forecast for Cook Inlet basin showing increments of reserves and resources identified by engineering and geological analysis discussed in text.” e Inthe DNR study,the only firm deliverabilities are for reserves estimated by decline curve analysis and material balance.The material balance resources would be realized through the spending of additional capital for development (Beaver Creek)or for compression (Ninilchik).Timing is determined by economic drivers. e The DNR study forecasted 863 BCF of Proven Developed Producing reservescomparedtothedeclinecurveanalysisperformedbyPRAforecasting729BCF >of reserves. o A major difference in decline curve analysis performed by PRA was apparent at Beluga River Field where the DNR study estimated 377 BCF remaining reserves and PRA estimated 207 BCF. o The predicted production from decline curve analysis was similar in both studies;both DNR and PRA showed decline curve analysis predictions from existing wells falling below projected demand in the 2012-2013 timeframe. e The DNR study forecasted Additional Probable Reserves of 279 BCF based on material balance calculations,while PRA did not perform material balance calculations. e In both studies,the four (4)Fields identified as having greatest remaining potential and selected for detailed geological analysis were:Beluga River,North Cook Inlet, Ninilchik,and McArthur River Grayling gas sands. Reported were: o Potential gas resources (from geologic analysis of 4 fields above)estimated to be 353 BCF o Possible gas resources of 643 BCF (50%Risked case)estimated from lower confidence pay intervals Potential of Future Gas Wells in Cook Inlet: e Drivers required for future Cook Inlet reserve development include: o Execution and RCA approval of gas contracts o Predictable timeline and standard for regulatory approval of negotiated gas pricing structures o Additional regional industrial gas demand,including LNG exports. o Additional well-capitalized exploration and development companies committed to develop Alaskan resources o Government action to facilitate and accelerate development of necessary infrastructure and permitting e Challenges facing future Cook Inlet development include: o Possible discontinuation of LNG exports from the region Reduced industrial demand (e.g.,regional fertilizer manufacturing) Success rates in exploration and development Higher relative regional costs for exploration,development,and production High level of activity in reserve development needed to meet demand o Probable decline in production rates from future wells in existing fields e Minimum requirements to meet demand in Cook Inlet gas market until 2020: o Anew source of gas,such as imported LNG or other in-state reserves,could be required as early as 2013,if ongoing drilling or drilling success does not continue at the 2007-2009 pace.00005 762 BCF in Report included 33.7 BCF estimated for 4 remaining 2009 Wells Gas storage will maximize Cook Inlet gas deliverability potential and more closely match local demand curves and production rates. To meet projected demand for the next decade,185 new wells will be needed, which is a 45%increase over the number of wells drilled in the 2001-2009 period Development costs for this time period are estimated'at $1.85 to $2.8 billion,an increase in total capital investment of 54-180% To incent this substantive increase in investment levels,or to bring a new source of gas to Cook Inlet,utility customers should expect to pay significantly higher gas prices Figure 2 shows recent history and future wells estimated to meet CI gas demands through 2020. The well count assumes average well performance of 2007-2009 wells,with initial rates and developed reserves degraded by 4.3%per year. 35 30 °NumberofWallsry-oes ot nes Wells Drilled,Wells Required &influencing Factors eee a een geneEst.Development Cost $1.0 -1.2 Billion .Est.Development Cost $1.85 -2.8 Billioneit.ee a age ; @ Wells Drilled @ Future Wells Needed 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Year,RE 2 a ee eT aT SE Dy mame Figure 2:Wells Drilled,Future Wells Required &Influencing Factors James Strandberg From:Gooding,James [GoodingJ@bv.com] Sent:Thursday,November 05,2009 2:22 PM To:julie.houle@alaska.govCe:James Strandberg;Banks,Kevin;Harper,Kevin;Rollins,MyronSubject:AEA RIRP natural gas forecasts,Nov 4 progress report Attachments:Cook Inlet supply estimations by Black &Veatch -20091104.pdf Julie &All: As agreed during our teleconference on Oct 28,2009,I am sending the attached progress report so you can witness how I handled the upgraded estimates of Cook Inlet producible gas that you provided during the telecon. Jim Strandberg has reminded me that this early report,which he has not yet reviewed,is meant only for internal discussion so I have watermarked the pages accordingly.Your careful handling would be appreciated. Results for the Base Case described in the attached file are being used by Black &Veatch to update the IRP model runs for Jim's AEA project. Regards. --Jim Gooding. James L.Gooding*|Manager Enterprise Management Solutions Black &Veatch Corp. 5151 San Felipe,Suite 1900 Houston,TX 77056 Office:(713)590-2264 |Fax:(713)961-1120 E-mail:GoodingJ@bv.com *Registered Professional Geoscientist (State of Texas) Certified Manager of Quality /Organizational Excellence (American Society for Quality) Cook Inlet Natural Gas Supply Estimations Viade for the Alaska Railbelt IRP Project Black &Veatch Corp. Enterprise Management Solutions November 4,2009 General Approach eo Purpose was to develop probability functions to quantitatively describe Cook Inlet gas production as a node in a probabilistic,supply-side decision-tree model applied to the IRP for 2010-2060 0 Black &Veatch gathered and integrated data from reliable sources -Production forecasts were preferred as input -Other resource estimates were accepted as input to scale production forecasts (this requires some assumptions about magnitude and timing of up-scaled production) e Black &Veatch did not attempt original geologic /geophysical evaluations of resources or petroleum-engineering evaluation of reservoir performance -Use of third-party data was limited to formulation of probability functions .Page -2 Draft Work Product -Not for Publication /Distribution Nov 4,2009 Cook Inlet Estimations Used in Decision Tree Model e Decision Tree 1.7 (Oct 16,2009) -Cook Inlet grand total production forecast (State of Alaska DNR,May 5, 2009)as "Legacy”sub-node -Enhanced future performance estimated as sub-nodes called "Re- developed”and "New-E&P” -Represented "Re-developed”and "New-E&P”sub-nodes using scalars derived from Cook Inlet resource estimates published by Netherland Sewell &Associates (2007)and the Potential Gas Committee (2007) ©Decision Tree 2.0 (Nov 4,2009) -"Legacy”sub-node (as in 1.7)but re-scaled using new estimate of total producible gas (DNR,Oct 28,2009) -"Re-developed”and "New-E&P”scalars (as in 1.7)replaced with new scalars derived using new estimates of total producible gas (DNR,Oct 28, 2009) ;Page -3 'Draft Work Product -Not for Publication /Distribution Nov 4,2009 BLACK &VEATCH Cook Inlet Estimations Used in Decision Tree Model o From DNR production forecast (May 5,2009): A.Integrated "North Cook Inlet +Beluga”=665.3 Bcf B.Integrated "North Cook Inlet +Beluga +Ninilchik”=750.0 Bcf C.Integrated "North Cook Inlet +Beluga +Ninilchik +Trading Bay +Kenai”= 909.6 Bcf e From DNR updated producible-gas estimations (Oct 28,2009): D.Historically-producing reservoirs (updated)=860 Bcf (most likely value) E.Re-worked historically-producing reservoirs (updated)=430 Bcf (most likely value) F.Undiscovered reservoirs =400 Bef (most likely value) e Derived scalars (sequence of production escalations relative to May 5) 1.Assume easiest upgrade pertains to smallest footprint,so Scalar 1 =D/A = 1.29,and applies during 2012-2013 (May 5 Legacy curve before then) 2.Assume re-working requires expanded footprint,so Scalar 2 =(D+E)/B = 1.72,and applies during 2014-2015 (replacing Scalar 1) 3.Assume new discoveries require further-expanded footprint,so Scalar 3 = (D+E+F)/C =1.86,and applies during 2016-2039 (replacing Scalar 2) Page -4 Draft Work Product -Not for Publication /Distribution Nov 4,2009 BLACK&VEATCH Cook Inlet Estimations Used in Decision Tree Model 2.0 e Revised Cook Inlet production (solid curve)combines Legacy +Re-developed + New-E&P sub-nodes by application of three successive scalars -and decision tree uses 100%of this combined node in all years through 2039 Supply-Source Nodes in Natural Gas Decision Tree 2.0 --Cook Inlet production (with re-development and new discoveries) ---Cook Inlet production (known reservoirs with projected decline) 350 : 2010 Probabilistic vs.Deterministic SG 300 t\---a----;cobeseeseeseeeeeeeel wee eee ee erences *-Each curve overlies a series of 1-year >(2010-2019)or 5-year (2020+)statistical Oo functionsS250qobeeOct ae S \ .Underlying statistical functions drive the Ss \2019 probabilistic decision tree=]200 om OO -"ss oe °Graph approximates the "expectation” $N values in a simplified deterministic 'ce 150 Fone x calculation 2 SA ; ©100 forcedNaeeES®Ni 2 : Lu 50 See.ee See rr we.oe PE nw we ewe ee we ee ede eee eee re nen Ree eee eee ee ene ee 0 LJ T |J t J 2010 2015 2020 2025 2030 2035 2040 2045 Year _Page-5 Draft Work Product Not for Publication /Distribution _Nov 4,2009 e Timing,ramp-up schedules and performance capacities estimated by Black & Veatch from published &unpublished reports Supply-Source Nodes in Natural Gas Decision Tree 2.0 Bullet Line --Spur Line ---LNG Import with Storage 950 ''' B00 qos feeesscceeeteeeebevnneeee 2029|nn i ee |450 4 "eccececeeseeeect wee e eee e eee ee 2020...-a ean nSe-a 2024 AQ.foveenveeeeesseeefeeeenneeeeeeee Joeveeeeceeeceeenfeceeeeneceeettnfeeeeetnneeeeetteeeetsnneteetenfeeeeetnnnenee 950 fl sf300ovr2017p;:.:.ExpectationValue(MMcf/d)Each curve overlies statistical functions that drive the probabilistic decision tree Graph approximates the "expectation”values in a simplified deterministic calculation sree pe erereiy 2013 @---fi--------}beectteeceeeeeeetedecee srroteataeatectafesteeastecaseceed|prvosestectateccatbesoseasestasescas 2010 2015 2020 2025 2030 2035 2040 2045 Year ;Page -6 Draft Work Product -Not for Publication /'Distribution _Nov4,2009 | Base Case in Natural Gas Decision Tree 2.0 e Cook Inlet production includes successive amounts of produciblegas estimated for known,re-developed and new (undiscovered)reservoirs e LNG imports with storage (97 MMcf /d,nominal) e Stand-alone ("bullet”)pipeline from North Slope (300 MMcf /d,nominal) Risk-Based Natural Gas Forecast "Bingo Card” Sequence of nodes that are available for pooling into the Railbelt Combined Supply @ =Supply node fully functional ©=Supply node in ramp-up mode Each node defined as a probability-of-occurrence function in units of annualized MMcf /d Model Node 2010-2019 2020-|2030-|2040-|2050-101/11]12 |13}14]15]16117118]19 |2029 |2039 |2049 |2059 Cook Inlet Gas 3 ||Production eleleleleiel/eiel/e/eleiel\eie (3 elements)3 | Bullet Line from ;||!North Slope o|lo};o|e]|e ee ei eleie ee Spur Line from AGIA Trunkline LNG Imports olele(incl.Storage)@ tC @ @ e eo;@ |@;@ 3 ee;@ |@ Page -7 Draft Work Product -Not for.Publication /Distribution ;Nov4,2009 _ Total Supply Outlooks in Natural Gas Decision Tree 2.0 e Base Case meets anticipated P50 gas demand (with P90 to P50 supplies)-at least through 2019 and possibly beyond BASE CASE:North Slope pipeline =Bullet -e-90%-o -50%-o-10%---P50 demand 380 360 +SR SR nn REE GER SR a SRR SRE GO an aE Sa a 340 4 3 soS20 te Pe iP ELE E:T SEO ESS A ESoO:'':'''::::'':''=300 top -tep\A BY ME pe pe eG HG GG he GO=AY ne ye >be nneNodeneeccobeagece ce nnenecdanecccchesncnndecsesnadennenen eeesCoenseenaaa.fo EeS4$-__+_._9-___4+_+__+__+__4-_+ YQwo :: STE ee a aaa aa aa ae a a ae O Note:Inflection of demand curve at 2020 is an artifact of the changein -- i ':''granularity of the date line. 180 i T T i T T T T i T T T i i 2010 2012 2014 2016 2018 2020-2030-2040-2050- 2024 2034 2044 2054 Year Page-8 Draft Work Product -Not for Publication /Distribution Nov4,2009 BUILDINGAWORLD OF,DIFFERENCES Price Forecasts from Natural Gas Decision Tree 2.0 eo Price forecast uses decision-tree output as one input -Decision tree deals only with supply-side issues of forming pooled gas supplies from various model nodes -Price forecast uses supply outputs (P90,P50,P10)from decision tree as inputs for price forecasts e Price forecasts are deterministic calculations based on empirical price relationships -Focus on estimating "city gate”prices that would be proxies for fuel | procurement plans by electric-power generators -not retail consumer prices -Historical relationships between price and supply-demand imbalance using data from Energy Information Administration and Black &Veatch research -Price adders estimated for transportation costs associated with some nodes -All-in delivery costs for imported LNG } -Pipeline tariffs -Comparison with price forecasts for other natural gas market hubs _Page-9--Draft Work Product -Not for Publication /Distribution Nov4,2009 Base Case predicts Railbelt "city gate”prices lower than at Henry Hub LA until about 2018-2020 e Analysts expect Henry Hub prices to decline as L-48 shale gas comes to market and as AGIA &Mackenzie pipelines begin to flow-at which point HH pricesinvertrelativetoAlaska --BASE P90 Price:---BASE P50 Price omme BASE P10 Price --#-North Fork contract floor &ceiling eeeeeee NYMEX Futures (Oct 8,2009)(5)-e-AEO 2009,$2007 (March 2009)(6) 30 GasPrice($US/MMBtu).Note:Prices for the Spur Case and Cook case are expected to be higher than those shown here for the Base Case. 9 2010 2020 2030 2040 2050 2060 Year _Page-10 Draft Work Product =Not.for Publication /Distribution Nov 4,2009 | Cook Inlet supply node estimations Cl Nodal Fn Black and Veatch Draft /Preliminary Work Not for Publicati moar Distribution Estimation of Probability Functions for Cook Inlet Production Sub-Nodes Example for 2017 Probability-of-DKNY Forecast of May 5,2009 Attainment Function- Sub-Nodes &Scalars (B&V curve fit to Re-sNew-E&P "New-E&P"Monthly by Pool,Grand Total""Legacy"developed Data in Columns A:B were used to derive the supply-node probability function in Columns Note 6 D:E.For each year in the DNR forecast,similar functions were derived (Fig.3)and used for the "Legacy"sub-node. To estimate "Re-developed”and "New-E&P"sub-nodes,scalars were applied to Note 7 corresponding "Legacy"functions.Scalars were estimated from NSAI and PGC estimations of additional gas resources for Cook Inlet. Once probability functions were estimated,choices were made about how to sequence the "Legacy","Re-developed",and "New-ESP."sub-nodes into the decision-tree Monte Carlo simulations.In Ver.1.7,sub-nodes were allowed to exist as "Legacy"(all years through 2039),"Re-developed”(2012-2039),"New-E&P 1"(2014-2016),"New-E&P 2”(2017-2039). Note 8 In years where all sub-nodes were allowed to exist,Monte Carlo simulations considered Note 9 relative likelihoods of the sub-nodes as Legacy :Re-developed :New-E&P =70 :20 :10.Logistic function)1"2"The net result of phasing the three Cook Inlet sub-nodes into the decision-tree gas supply simulations is shown in Fig.4. Mcf MMcf /d 1.00 1.10 1.42 1.73 PEP ORMR grater ge eataunnpareganersy i Ae ¥1/1/2017 130,854 95%117.73 117.73 129.51 167.18 203.68 BUILDING A WORLDOF DIFFERENCES mii oud 21/2017 129,680 90%119.48 119.48 131.43 16966 206.70 Components of the Natural Gas Decision Tree 1.7 3/1/2017 =128,553 85%120.56 120.56 132.62 171.20 208.57 e Cook Inlet Gas Production (Supply-Source Node) 4/2017 127,400 80%121.38 121.38 133.51 172.35 209.98 -Data Source:State of Alaska Department of Natural Resources (DNR,May 2009) 5/1/2017 126,279 75%122.05 122.05 134.25 173.31 211.14 -Main Assumption "Legacy”physical production =base supply capability of this node 6/1/2017 125,114 70%12264 12264 13490 17414 212.16 Cook inet Froguction nets for Decisron Tree "Legacy”Hose?-D>-Decadal 2010-2019 (Ver.10-Logstic)7HN/2017 =124,045 65%123.17 123.17 135.49 174.90 213.08 Pater 2010-2019 (Ver.1.7 -Triang8/1/2017 122,899 60%12367 12367 136.04 17561 213.95 en9/1/2017 121,796 55%12415 12415 13656 176.29 214.78 |Ve ALAA10/1/2017 120,756 50%12462 12462 137.08 176.96 215.59 so Vy ye Figure 3 11/1/2017 119,672 45%125.09 125.09 137.60 177.62 216.40 i 7o%4 AY. 12/1/2017 118,649 40%125.57 125.57 138.12 178.30 217.23 S con oe 35%126.06 126.06 138.67 179.01 218.09 3 50%4 30%126.60 126.60 139.26 179.77 219.02 ZB 40%4 i 25%127.19 127.19 139.90 180.60 220.03 8 30% 20%127.86 127.86 140.64 181.56 221.20 20%4 15%128.67 128.67 141.54 182.72 222.60 10%4 10%129.75 129.75 142.73 184.25 224.47 ae 00 so b00 se x00 3805%131.50 131.50 144.65 186.73 227.50 Myact id *page-13.Draft Work Product-Not for Publication/Distribution octts,ams:Estimation of Scalars for Sub-Nodes: "Legacy"1.00 Function derived from production forecast C3 an "Re-developed"1.10 Arbitrary 10%enhancement,comparable to Components of the Natural Gas Decision Tree 1.7 some re-worked gas reservoirs in L-48.e Cook Inlet Production based on DNR forecast ("Legacy”)with B&V¥estimations for "Re-developed”and "New-E&P”production "New E&P 1"1.42 =(1,726.4/1,211.8)Supply Source NodeswnNaturalGas Decision Tee 17 Essentially,this is the "2P /1P"volume ratio from the --Cook inlet Re-developed Production |Netherland Sewell (NSAI)report of 2007. Probabilistic vs.Deterministic "New E&P 2"1.73 =(2,100 /1,21 1 .8)Each curve overlies a series of i-year Potential Gas Committee (2007)estimated "Most Likely"resources aoe ear 2020 +)Figure 4 as 2,100 =400 (probable)+700 (possible)+1,000 (speculative). Ratioed that 2,100 to NSAI's 1P number. ("Most Likely"is the mid-range defined by PGC.) Underlying statistical functions drive the probabistic decision tree Curve values (graph)approximate the"expectation”values in a simplifieddeterministiccalculation ExpectationValue(MMecf/d)ee A taeeemn ag nee ce eee een neta scene nee cbr ee ea cteecee 2010 2015 2020 2025 2030 2035 2040 2045 Your _fage-i1.Draft Work Product -Not for Publication/Distribution|oct16,a09" Page 1 of 1 10/28/2009 1:00 PM Appendix B .n-State Needs Study Executive Summary This In-State Gas Demand Study projects the potential demand from Alaska residents and industries for natural gas and propane that would be available with construction of a natural gas pipeline to commercialize North Slope gas.The purpose of the study is to meet the requirements of §157.34(b) of the FERC open season regulations for Alaska natural gas transportation projects.This study facilitates identification of at least five off-take or delivery points and potential delivery volumes at various locations along the pipeline.The study is also intended to allow the initial design of in-state delivery tariffs,which would help potential pipeline customers plan for the initial open season. Study Scope and Approach Potential demand is presented for two different future timeframes:(1)the Year 1 to 5 timeframe, which captures the demand in the first five years of operation of the gas pipeline;and (2)the Year 10 to 15 timeframe,which captures potential demand of various economic development projects or prospects that are expected to take a longer time to develop. The study considers the two pipeline route configurations proposed by TransCanada:1)the A/berta Line -from the North Slope of Alaska to Alberta,Canada following the Alaska-Canada highway,and 2)the Valdez LNG Line-from the North Slope to Valdez,Alaska,terminating at a liquefied natural gas (LNG)facility and marine terminal'. The study evaluates potential future demand for natural gas and propane for industrial uses,electric power generation,and heating demand from the residential and commercial sector,including the military.Stakeholder interviews were valuable in developing assumptions used in the demand projection models for each of the sectors.Industrial and electric power demand analyses were based on an assessment of several different future scenarios.Analysis of the industrial scenarios was based on an evaluation of the economic viability of various potential industrial prospects.Electric power scenarios were based on four future power generation scenarios currently being considered for the Railbelt?region.Residential and commercial sector heating demand analysis involved looking at increasing penetration rates as well as expansion of service areas,primarily in the areas with existing piped natural gas distribution systems. The study employed a probabilistic approach to estimating natural gas demand.Projecting future demand that may occur 10 or more years into the future is challenging due to the considerable uncertainties that exist,particularly regarding future industrial and power demand.Furthermore,the possibility of future increases in Alaskan gas production from Cook Inlet or the Interior,and the rates of fuel-switching add further complexities to projections of in-state demand for North Slope gas.The probability analysis considered these high levels of uncertainty that exist about the energy situation in Alaska.The results of the probability analysis are summarized according to the three most probable industrial demand cases;these are presented in Table ES-1. 'The economics and natural gas demand of the new Valdez LNG facility with an associated marine terminal, were not analyzed in this study.Based on information provided by TransCanada,the Valdez LNG facility is assumed to require 3.0 Bcf of natural gas per day. 2 For this study,the Railbelt is defined as the service areas of the six Railbelt electric utilities including Chugach Electric Association,City of Seward Light and Power,Golden Valley Electric Association,Homer Electric Association,Matanuska Electric Association,and Municipal Light and Power.The service areas of ENSTAR Natural Gas Company and Fairbanks Natural Gas are within the service area boundaries of these electric utilities. 3 More detailed discussion of the probability analysis and associated assumptions for the different sectors is provided in the main body of the report. NorthernEconomics ES-1 Appendix B In-State Needs Study In-State Gas Demand Study Major Findings Historically,Alaskan demand for natural gas has been greater for gas-intensive industries than for all other sectors combined (i.e.,power,residential,commercial,and other industrial).Hence,the future demand for natural gas in the state of Alaska is substantially affected by the future of Alaskan gas- intensive industries. Table ES-1 summarizes the results of the probability analysis;it shows results for three demand scenarios categorized as "No Industry”,"Current Industry”,and "Growth Industry”.Recognizing that no in-state gas-intensive industrial load is very certain in the future,the No Industry case represents in-state demand without a large industrial load.The Current Industry case represents a continuation of current trends,with a facility representative of the demand required by the Nikiski LNG terminal operating at full capacity.Finally,the Growth Industry case represents a scenario in which a facilityrepresentativeofthedemandoftheexistingLNGfacilitywillexpandtodoubleitscurrentcapacity, but no greenfield projects will be built in years 1 to 5 of pipeline operations.Greenfield (or new) industrial projects are not assumed to be built at the same time as the pipeline because the joint demand for labor and materials could significantly increase the capital costs for a new facility,causing it to be uneconomic.Furthermore,unless owners of the greenfield industrial projects are to secure gas supply and commit to pipeline capacity in the early open seasons,it is unlikely that they would have sufficient gas to support the greenfield projects in the initial years of pipeline operation.In years 10 to 15,greenfield projects with reasonably likely economic feasibility are included under the Growth Industry case. Table ES-1 also shows the percent chance that each case will occur.The No Industry case is more likely in the first years of pipeline operation than in later years.Under the Alberta project,the Current Industry case is the most likely of the assessed scenarios. Table ES-1.Total In-State Natural Gas Demand Estimates for Three Scenarios,Alberta Project (MMcfd) Year 1 to 5 of Pipeline Operation Year 10 to 15 of Pipeline Operation %Chance %Chance %Chance Demand %Chance Demand of this will Exceed of this will Exceed Demand Scenarios Demand scenario this Level Demand scenario this Level Alberta Project _.. No Industry 260 29 71 290 14 86 Current Industry 490 38 26 520 18 65 Growth Industry 740 12 3 1,120 6 2 Source:Northern Economics,Inc.and SAIC,Inc.,2009. Note:MMcfd is million cubic feet per day. Figure ES-1 shows historic consumption of natural gas and the projected demand by sector.The projected demand totals are those depicted by the Current Industry case for the Alberta Project for the first five years of pipeline operations.Since 2006,the Agrium ammonia-urea plant has ceased operation and the LNG plant owned by ConocoPhillips and Marathon has reduced LNG production. The export license for the plant expires in 2011;consequently,the projected gas-intensive industrial demand shown in Figure ES-1 is uncertain. ES-2 NorthernEconomics Appendix B .n-State Needs Study In-State Gas Demand Study Figure ES-1.Historic and Projected Total Annual Average Daily Demand for Natural Gas,Current Industry Case for the Alberta Project 600 4 Projected Demand $50 -ae _ 500 -: ie,'deiion 450 - po 400 +Thadd dda :'3¢ 7q ;29 350 |B76 59 p59 B24 B34 P74 173 28d 2 aERTHE :ue on3300|TELE =ap Eo]}|)mindustrial =|;a.4 p32 200 4 ai lh ie r 2 mae "'"Sore F LI [|03 6 .%if w Residential so1iF tT baba kid &py yt 2q pFg & TP Ld PIED E ak Commercial . :". a ra . 100 {Fd ed PEL | 4 50 od £19 P19 $19 p1q B14 bo;foo m Power :2a i Ped -_ad 70 0 T T T T T T T T 1 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Year Year 1-5 10-15 Source:Historical data are from the Division of Oil and Gas,Alaska Department of Natural Resources.Projected demand in Year 1 to 5 and Year 10 to 15 of pipeline operations are based on the results of this study. Notes:Historical values for industrial sector include gas consumption for the LNG facility,the Ammonia-Urea plant from 1998 to 2007,and for other small operations such as for military bases in Anchorage,the GTL facility, Tesoro refinery,the small liquefaction facility that ttansports LNG to Fairbanks Natural Gas,etc.Gas consumed in field/iease operations is not included in the values shown above.The sum of the projected values for Year 10- 15 in this figure does not match the total Current Industry case demand in Table ES-1 due to rounding. Figure ES-2 presents the average monthly demand during a calendar year.The monthly average daily demand varies by about 130 million cubic feet per day (MMcfd)over the year.Demand from the industrial sector helps to moderate seasonal variation in the residential,commercial and power sectors,which can experience demand as low as 138 MMcfd in the summer and as high as 271 MMcfd in the winter.The industrial sector curtails its demand if needed in the winter. NorthernEconomics ES-3 Appendix B In-State Needs Study In-State Gas Demand Study Figure ES-2.Typical Total Average Daily Demand for Natural Gas by Month 550 500 4so +f}-om @ Residential * 400 +4 .}-and ;Commercial 350 +4 : }- {Pt -=yy p 300 +|_m Power u = =250 +4 -- 200 7-7)m@ Industrial and Other 150 ++- 100 --4 - 50 +4 - 0 T . T T T T j T T : T :-T Td Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Source:Data on historical natural gas usage are based on information provided by the Alaska Department of Natural Resources,for the years 1998 to 2009. Note:Industrial demand above excludes historical gas volumes used for field operations and for fertilizer production at the Agrium plant. This study assumes that in the interim years before the proposed pipeline becomes operational, measures to address the natural gas deliverability problems in Southcentral Alaska will be put in place. These measures could be in the form of building new underground gas storage facilities and promoting demand side management such as entering into agreement with industrial gas users on demand curtailment during peak winter season when total demand exceeds supply.It is anticipated that an additional option will be available for managing seasonal swing once the TransCanada Alaska pipeline is in service.Typically,pipelines can deliver more gas during the winter when ambient temperature is lower due to an increase in the compressor efficiency.This enhancement in performance is approximately 5 percent of the nominal design capacity of the pipeline;hence,thispipelinefeaturecanbeaflexibletoolforin-state gas shippers to meet their winter load demand bycontractingshort-term firm transportation services during the peak load periods.The development of incremental gas storage facilities,implementation of load shedding demand side management and availability of incremental pipeline capacity during winter allow in-state gas shippers to contract capacity on the pipeline based upon their annual average volumes instead of winter peak demand volumes.For the purpose of calculating an indicative in-state delivery tariff,the projected annual average daily demand for North Slope gas will be used. ES-4 NorthernEconomics Appendix B n-State Needs Study In-State Gas Demand Study Cook Inlet Supply Figure ES-3 shows historic Cook Inlet natural gas production from 1998 to 2009.Although production has been declining since 2001,the Cook Inlet basin is anticipated to continue production well into the future. Figure ES-3.Total Historic Cook Inlet Natural Gas Production 250 soo a\pe iNfo 150 BCF/Year100 50 0 T T T T T T T T T T q T Li T 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 Source:Alaska Department of Natural Resources,Division of Oil and Gas. The Alaska Department of Natural Resources,Division of Oil and Gas (DOG)recently issued a report that evaluated the remaining Cook Inlet natural gas reserves.Table ES-2 presents the DOG estimates for Cook Inlet natural gas volumes.The more conservative estimates are based on engineering analyses using decline curve and material balance techniques.According to DOG,the geologic analysis for the four major fields in Cook Inlet is strong enough to classify these volumes as reserves that have the potential,if developed,to meet the local demand well into and possibly beyond the next decade.Furthermore,there are potential exploration targets throughout the basin that could provide additional gas resources,though there is less certainty for this geologic estimate compared to the gas reserves engineering estimate. NorthernEconomics ES-5 Appendix B In-State Needs Study In-State Gas Demand Study Table ES-2.Remaining Cook Inlet Natural Gas Volumes by Type of Reserves and Resources Location/Type of Reserve Derivation of Estimate Volume All Fields (Bcf) Proved,developed,producing Decline Curve Analysis (DCA)863 Probable Material Balance (MB)-DCA (1,142-863)279 Four Fields (Beluga River,North Cook Inlet,Ninilchik,and McArthur River)-; High-confidence pay intervals Geologic PAY (GP)-MB for 4 fields (1,213-860)353 Lower-confidence pay intervals GP+50%-risked Potential Pay-GP (1,856-1,213)643 Total Estimated Reserves 2,138 All Fields Higher risk contingent resources Exploration Leads,Basin-wide 300 Total Estimated Reserves and Resources 2,438 Source:Values shown in the table are from,Hartz,J.D.,et al,2009.Preliminary Engineering and Geological Evaluation of Remaining Cook Inlet Gas Reserves.Alaska Department of Natural Resources. The Cook Inlet basin produces enough gas to meet annual average demand.However,supplying the required volumes during spikes in demand on very cold days in the winter is challenging for the current system.Currently,wells are being drilled and storage facilities are being developed,which indicates that investment is being made to address the deliverability issue.The DOG report notes that "infill drilling,perforating undeveloped sands,and targeting marginal reservoirs are effective ways to add reserves to replace production.”However,all these costs will need to be absorbed into a market that requires relatively small volumes,which will likely place upward pressure on gas prices. DOG assumes that "either a significant amount of gas is found by explorers to meet industrial use in the future,or that export of gas out of the basin will stop at the end of the current license period” (2011)for the LNG plant.DOG further assumes that no new demand will occur until reserves are developed to satisfy the market,which requires that sufficient risk-capital be available to explore and develop the higher risk contingent and prospective gas resources. After the proposed spur line to Southcentral Alaska is completed,natural gas prices from both Cook Inlet and the North Slope will begin to converge.Local utilities,as expressed in the Railbelt Integrated Resource Plan (RIRP)(Black &Veatch,2009),have indicated a desire to reduce their dependence on natural gas with increased demand side management and energy efficiency,increased use of renewable energy sources,and expanded transmission systems.However,even with such diversification and new facilities,natural gas remains a major energy source for the Railbelt,even 50 years into the future.Given this long time frame,utilities would seek to diversify their supplies of natural gas and would consider gas from the North Slope,coal bed methane,landfill gas, underground coal gasification,and other sources.The utilities have indicated that Cook Inlet sources would remain as a very large percentage of their natural gas supplies even if North Slope gas is less expensive. Net In-State Demand for North Slope Gas Discussions with several Southcentral utilities indicated that they might look to source 5 to 50 percent of their total gas demand from the North Slope.These percent estimates,when aggregated,suggest an average daily utility demand of about 40 MMcfd of North Slope Gas in the Southern Railbelt region in Years 1 to 5.In addition,gas-intensive industrial demand in the Southern Railbelt region for the current industry case is assumed to be met solely by North Slope gas.Therefore,the total demand in ES-6 NorthernEconomics Appendix B #n-State Needs Study In-State Gas Demand Study the Southern Railbelt region that will be supplied by North Slope gas is projected to be about 270 MMcfd for the Alberta route. The total net demand for North Slope gas including the projected utility and industrial sector demand in the Northern Railbelt region and Livengood is projected to be about 340 MMcfd in Years 1 to 5 after pipeline operations begin (as shown in Figure ES-4). Figure ES-4.Total Natural Gas Demand versus Total North Slope Natural Gas Demand,Current Industry Case, Year1 to 5 of Pipeline Operations,Alberta Project 500 400 .280 300 =:| m Industrial Sector 2u = 2 200 o 2700... 100 @ Utility Sector 0 t Total Natural Gas Demand Net North Slope Gas Demand Source:Northern Economics,Inc.,and SAIC,Inc.,2009. The Valdez Project Not counting demand from a new Valdez LNG facility,the Valdez route is estimated to have a higher gas demand than the Alberta route for the three demand scenarios presented above.This is due to the additional industrial demands in the Valdez area with the availability of natural gas.For the first five years of pipeline operations,the projected demand for the No Industry case,Current Industry case,and Growth Industry case,are 270,500,and 750 MMcfd respectively;and the percent chance of these scenarios happening are 61 percent,30 percent,and 9 percent respectively. The total net demand for North Slope gas for the Valdez Project under the Current Industry case is projected to be about 350 MMcfd in Years 1 to 5 of pipeline operations. NorthernEconomics ES-7 Appendix B In-State Needs Study In-State Gas Demand Study Potential Propane Demand The natural gas stream in the main gas pipeline will contain large volumes of propane and other natural gas liquids;energy needs outside of the Railbelt could be supplied with propane.It is anticipated that the propane will be less expensive than distillate fuels on an energy-equivalent basis in many areas of the state,and there is keen interest in reducing the cost of energy,particularly in rural Alaska.In the initial years there is a 48 percent chance that the propane demand will be about 3,500 bpd.Ten years later there is a 67 percent chance that demand could increase to about 35,000 bpd as the propane infrastructure is built around the state.This study anticipates that propane extraction facilities would be built in the Fairbanks area and in Cook Inlet or Valdez,depending on the route.A comparison of the potential tariffs for a small propane extraction plant and trucking costs indicate that it would be less expensive to truck propane from Fairbanks to communities in the pipeline corridor and on the road system than to pay the tariff for a small plant. A proposed propane extraction plant at Prudhoe Bay could have lower transportation costs to Arctic and western Alaska and supply propane to those regions.A Prudhoe Bay plant that may be built in the near term could facilitate a faster conversion to propane in the Fairbanks area and along the road system,thus potentially increasing propane demand in the initial years. Potential Off-Take Points and Volumes Figure ES-5 shows the potential total energy demand (as natural gas equivalent volumes)along the pipeline corridor.This figure shows the demand by community,as well as for potential spur line off- take points at Delta Junction or Glennallen,assuming a Richardson Highway or Glenn Highway spur line is built.If a Parks Highway spur is built instead of a Richardson Highway or Glenn Highway spur, similar demand would exist at a Parks Highway off-take location.The spur line off-take volume represents the current industry case for the Southern Railbelt region. ES-8 NorthernEconomics Appendix B .n-State Needs Study In-State Gas Demand Study Figure ES-5.Potential Net Demand along the Pipeline Corridor,Current Industry Case, Year1 to 5 of Pipeline Operations A i * . *Prudhoe Bay "4 to a \.a f/|LEGEND ©Communities with less than 1 MMcfd Demand Potential Spur Line Offtake Point 100 [J Miles 2 Wiseman Coldfoot faYY? pf:yukor OQ}Stevens aSw,Vilage " Livengood Me 9 MMctd = Fairbanks Area/River Norther Railbelt Zw55MMctd i Harding -Big Delta,'Pech Delta Junction,> Deltana,Fort Greely te,1 MMctdAlternativep OoSpurlineOfftake/-ety DotAlbertaProjectesNie//tate TM"270 MMcfd f o€Tetiin YYaAlternative'lack.;. Spurline Offtake /\/Alberta Project'_B.\,270MMctd &%©EY)o,2 +f Northway Junction/zB S &Northway Village %©%|x 22% "ge Spurline Offtake/°iP Cone Valdez Project (pO Glennatie{Total Southern 270 MMcfd mr:meen |Railbelt Demand i Copper Center =Willow Creek430MMcfdawel4AnchorageglenWid7Tonsina Cook Inlet /Cy.160 MiMctd 4 ry)4,if.veiee:i tf Icijoe aeid. .i Source:Alaska Map Co.based on the results of this study,2009. NorthernEconomics Appendix B In-State Needs Study In-State Gas Demand Study Table ES-3 shows the most likely off-take points based on the analysis conducted for this report.A proposed gold mine at Livengood is a likely candidate for a delivery point,and one or more off-take points may be required in the Fairbanks area,and another one to provide for a Parks highway spur line to Southcentral Alaska,or for future growth along the Parks Highway.The communities in the Delta Junction area plus Fort Greely are a likely location for an off-take point,which could be on the main gas pipeline or on a proposed spur line that would generally parallel the Richardson and Glenn highways to the Cook Inlet region.The communities in the vicinity of Tok may not have sufficient demand at present to justify an off-take point,but there is the potential for future mineral development and associated demand in the region around Tok.Glennallen and Valdez would be obvious off-take points for a line to Valdez since Glennallen would be the location of a spur line to Southcentral Alaska,and Valdez has community demand plus demand from the Alyeska marine terminal. Table ES-3.Potential Off-Take Locations along the Alberta Line and the Valdez Line Route Location Alberta |Valdez Livengood 1 1 Fairbanks 1-2 1-2 Parks Highway spur 1 1 Delta Junction area/Richardson Highway spur 1 1 Tok 1 NA Glennallen NA 1 Valdez NA 1 Total 5-6 6-7 Source:Northern Economics,Inc. At this time,ten years prior to the planned commencement of the TransCanada Alaska pipeline operation,the pro forma in-state gas tariff for the upcoming open season will be an estimate based on the demand net of Cook Inlet supply as noted in this study.The actual tariff for the pipeline will be highly dependent on the actual contracted volume of the pipeline,which will be determined in the initial open season and subsequent open seasons. ES-10 NorthernEconomics FAIRBANKS Economic Development Gia a Ror Por(a Ree pet par 301 Cushman St.,Suite 301,Fairbanks,AK 99701 January 30,2009 Dear Sir or Madam, It is with a sense of pride and accomplishment that I present to you the In-State Gas Pipeline report. Task Force members have given massive amounts of effort and energy to make this document a competent,analytical analysis of potential gas pipeline projects being developed in Alaska. Collectively,the committee spent over a thousand man-hours drafting this report.I want to thank each member for the time,knowledge and determination that enabled us to complete this analysis. A special thank you goes to Frank Abegg,the Chairman of the In-State Gas Pipeline Task Force.His leadership was remarkable.|also want to show my appreciation for Jomo Stewart,FEDC's Energy Project Manager.His staying power doing countless edits and hours upon hours of redrafting is an example of professionalism at its best. I also must thank those companies whose projects this report evaluates.ENSTAR,Alaska Natural Gas Development Authority (ANDGA),Fairbanks Natural Gas (FNG),Anadarko,Doyon,Limited,TCAlaska and DenaliAlaska all voluntarily contributed time and information to this report. I am sure that several companies that participated do not believe this report is an accurate portrayal of their project's benefits to our community or to the State of Alaska.I appreciate and respect that.The goal of this report was to find value for our community and for the people of Alaska.It was difficult to balance all interests. The recommendations of this report call for stronger Alaska State leadership to create a system that will provide energy to Alaska communities on as equal a basis as possible.Alaskans deserve the high paying jobs and economic opportunities that cannot be obtained without affordable energy.That affordable energy is within our reach but not with Alaska's present way of doing business.For half of all Alaskans,Legislative regionalism and failure to invest Alaskan dollars in Alaska has contributed to a hollow sound when we hear the words "North of The Future”. Natural resources are our state's biggest blessing,but people are what will provide the solutions for a better future.With leadership we can find the way. Thank you, (aE. Jim Dedson Presidént and CEO Fairbanks Economic Development Corporation Phone:(907)452-2185 www.investfairbanks.com Fax (907)451-9534 1-888-476-FEDC . 11)Interior Issues In-State Gas Pipeline Supply Options Study Issued January 30,2009 Prepared by: Interior Issues Council: In-State Natural Gas Distribution Task Force and Fairbanks Economic Development Corporation {IM Table of Contents STUDY OBJECTIVE ......csccereeee 5 7 7BPwD>FNSB AIR QUALITY (PM 2.5)ccsccscsssssssccccsscscccossssecessencsssssssussssssstsuscescesrssseeesesnseneesnsueearsarsneseseseneesesnene 4.4 PARTICULATE MATTER (PM)2.5 NON-ATTAINMENT.......ccccccseccececsceceesseceeseesaesaesseceeesseneaecsaecnaeesaeesaeens4.4.7 FNSB Non-Affainment Boundary (PM 2.5)o.c.ccccccccccccsescessssecseesnssseensssecnsecesssecenessssssssssessseeeeesO 4.2 PM2.5 PaRTICLE ANALYSIS...wows de nueeeececucecucessueeseasecsceeuseeussencesusessssssssssssseeEO4.3.PM 2.5 STANDARD NON-COMPLIANCE CONSEQUENCES...bee usueeeseasanssesssensesccsenssessesscssssssssssacseseses 1D 5.ALTERNATIVES FOR ENERGY ...........cccssssssssnsccssnssassnsssnennonscussescessesesuesenessnaessssssasssasesnassessassnsesseases1D 5.1.DOo-NOTHING SCENARIO...se cecaaecucesacaeceaecnccanecauecaueesenaececeetesnacsecsaessussseseestesssaeeneee IG5.1.1 Do-Nothing Scenario:Electricity...saseeencacaesaeeesececuaesssouesessenaesecsssaecceceensesecsesetessnsersencesssee4G5.1.2 Do-Nothing Scenario:Heat..cee bese eecaeecuaeensuece caaeennensoaecncaeeenecerecucecntecstetssnetersee 195.7.3 Do-Nothing Scenario:Transportation Fuel...ese sece ees esecessaeeeseeesaeceecssetseneeceteseeentesatesneseneesOO5.1.4 Do-Nothing Scenario:SWOT Analysis...vvvssessunvassssssesassssisasissssssesesecsssssessesuunsasesesessse,20 5.2.COAL-ONLY SCENARIO..csoscsssssseesesusassersseesvuissnsasesisvsssesisssiasssiisssaenvseedl5.2.1 Coal-Only Scenario:"Electric ..ace eaneccasuausvencecaeecnaecaeecaeeessateesaaecaenaecuaeeecsaessasssssssecssesteessesZt 5.2.2.Coal-Only Scenario:Heat...see esegaseseeeecasccnsecesecsecessenuecesavcnenaesnertecenstsresesesseser2d5.2.3. CoalOnly Scenario:Transportation Fuel...ang ceseasecaeecsceaucesssstecuenssaessenssensuessesessaetsssssensnsle5.2.4 CoakOnly Scenario:SWOT Analysis...svsussesasesssensssateevavavusnuavasnsnsasesasesinsaveveseeseesseanes 22 5.3.SUSITNAHYDROELECTRIC DAM SCENARIO...seceecceeaaeeesecessaeseceauestsesecstecsceesaseoasseeetes225.3.4 Susina fiydtoelectiic Dam Scenario:0:SWOT Analysis aceccaeceesaceecesceeueeseccacereesssscsentsesseneesDo5.4 ANUCLEAR OPTION?wu...eee ceseeceereees secaseesaecaeseceseceaesnesaecusesecasecaeessseseuscesscesessseeascsasaasseasssaeesDo 6.IN-STATE NATURAL GAS MARKET...sesenenseunacansnnenetsncnecususssacuseseausecnesensessensesnenatenenasarseneanensnsLE 6.1 INTERIOR ALASKA GAS MARKET..eee bevsusecucausususeusunenceauensusueususuauesuasasay oceevonssensrssenesenenss D4 6.14.1 interior Market Growth and Penetration ..76 6.2 SOUTHCENTRAL GAS MARKET....A6.3.TOTAL INTERIOR AND SOUTHCENTRAL GasMARKET ..ee 6.4 Gas MARKET CONCLUSION secon tesisssususististavisiesssssesisisivisasvivenvtbtntieeeeeceseenveteve eee 30 7.GAS PIPELINES AND SUPPLY...........:c:csssssssssccsssnencssneccnscsrssenssssessessesnsesusesnassacscrsecesssseeesssccsestsssorsesOO 7.1.IN-STATE DELIVERY OPTIONS...as cussueeussessuestsessaeeasassnestecetsesseescsastsecsssssesasOT7.1.1 Alaskan Highway Line(TCAlaska or"Denal)dacaecececasaecaaecusececsassessaccnsessesssecsatesserssteeeesOd7.1.2 ANGDA Spur Line...wee nvvsusssssasstasasstvasivisininesessesssvivisisivivesssasesssesssseees BB7.1.3 ENSTAR Bullet Line...ses seeaaesecaaesensuaecnaeenenssseasesassasceateceussaeesssessesssserereesOO7.14 Fairbanks Natural Gas (Trucked LNG)...bu cesacececseeacceceenaecaaesssaaecausseccasasssstscssscsescsseseeees407.15 In-State Delivery &Supply Comparison...des cececeuscerscsuncecesanscessescecssscessses4d7.2.GAS BASINS (KNOWN AND POTENTIAL NATURAL Gas RESOURCES)...eceeeencessessnstenseccsaeescesstseense4 7.2.1 North Slope Basin...cesssussssssaststorsssesssssstussssnsesetviasssevessvesssmusasssssssesssisseeseeine427.2.22 Cook Inlet Gas BOSD cooccccccccccccscscscsssssssssssssssusssssaseseseseesessssssssssessssssssssisevasesavassasssssesssssesseeees 43 7.2.3 Gubik Gas Basin...ccceccccccccseccscssssesecsccsasensecesscesecesesecssessecssecnaecase snsssnasesasasssessasssssseesssessessess 40 7.2.4 -Ne@mana Basin .occcccccccccccccccsscccccnsssesssscssecssseesesscnsssscsseuseesssssssacensecassecsssecscssscssscsessecssscssscsseensFP 7.2.5 Yukon Flats Bait oo....cccccccccccccsscescncecnsecesnce csssecoancsueceaaesaceceaecseeescececsaecsscuececsssseseessaecneecssnssees 4 7.2.6 Copper RIvOr Basin ...cccccecccesscscecnsecnseensnsececosecaceseecnaensagncosesaeseesdensanenececncecsassnaeenssentesscenteesOO In-State Gas Pipeline Supply Options Study Page 2 7.3 GAS BASIN SUMMARY .....ccccsccscsscccesccsecesececusescesceeessuensussecateeeesecesveneseuseeunsncesucessseetsseecsesansssseesesereeOO B.CONCLUSIONS oun...cscscscsseceseresesssnscssncesceusrsnseaanenseceecanucanseccessessrcernssessacsecesrcesenecasers 51 8.1 FAIRBANKS NATURAL GAS LNG OPTION ......eccccececesecece ce esseece sesssesucesscusussansuascnseeessecoacsessesevesnseseenees DO8.2 ANGDA SPUR LINE ......cccccccecssseececssccecessceseccsasececnscteccesscessensceuceseassuaessssassesessecauesunsesseseesssnsavensneeesDO8.3)ENSTAR BULLET LINE ........cccccceeeesccce cece cosssseecesusucesensecesucevacseesteesucesecesensveneesesusesecsesetsesecsssateeesessseOO 9.RECOMMENDATIONS .........ccccssssscssccessecnacsecssernsecnstacsensncastacenacaecnanseconecassarsensnacensscassenssaceeersesrssnseneOO O.4 INFSTATE GAS SUPPLY uu...secscccceccseseuscececesuscuneucesecescuecusececeanestansesssucetsensusesenseeeeecseparausesessanseteneneneeQO Tables and Figures FIGURE 4-1:FNSB's PROPOSED PM 2.5 NON-ATTAINMENT BOUNDARY .......ceeeceesseceseecesrcoereecrsetesesescsssonseseeraunensFIGURE4-2:PM 2.5 EXCEEDANCES (2003-2008)...FIGURE 4-3:FAIRBANKS DAILY PM 2.5 LEVELS (WINTER 2005-2006)...FIGURE 4-4:EPA's PROPOSED PM 2.5 NON-ATTAINMENT BOUNDARY.FIGURE 4-5:FNSB'S AQUSTED PM 2.5 NON-ATTAINMENT BOUNDARYsins TABLE 4-1:EFFICIENCIES BY STOVE TYPE..."TABLE 4-2:CORDWOOD AND PELLET STOVE PM 2.5 EMISSION FACTORS... TABLE 6-1:FAIRBANKS NATURAL GAS SALES..TABLE 6-2:FARBANKS ESTIMATED GAS DEMAND ..-e-sssscaeTABLE6-3:FUTURE POTENTIAL INTERIOR ALASKA INDUSTRIAL GAS DEMAND.. TABLE 6-4:SOUTHCENTRAL GAS MARKET (2001-2006)...vsFIGURE6-1:SOUTHCENTRAL NATURAL GAS USAGE BY PERCENTAGE...FIGURE 6-2:PROJECTED SUPPLY OF AND DEMAND FOR COOK INLET GAS...TABLE 6-5:GVEA POWER PRODUCTION DATA (AUG.2007 THROUGH JULY0vovuseccsusssttvitiitecevssssiniensFIGURE6-3:SEASONAL RESIDENTIAL AND COMMERCIAL DEMAND FOR COOK INLET GAS (1999-2002).......... FIGURE 6-4:RAILBELT NATURAL GAS DEMAND...weFIGURE7-1:ALASKAN HIGHWAY LINE:NORTH SLOPE TO ALBERTA... TABLE 7-1:NORTH SLOPE GAS PIPELINE PROJECTS...FIGURE 7-2:GAS PIPELINE TARIFF ESTIMATES (SIME)... FIGURE 7-3:MAJOR U.S.SHALE BASINS...FIGURE 7-4:GAS SUPPLY/DEMAND BALANCE.IN N.AMERICA...FIGURE 7-5:ANGDA SPUR LINE..weesTABLE7-2:GAS PIPELINE TARIFF ESTIMATES... FIGURE 7-6:ENSTAR BULLET LINE...-TABLE 7-3:NATURAL GAS SUPPLY OPTIONS:TO FAIRBANKS... FiGURE 7-7:NORTH SLOPE BASIN.. FIGURE 7-8:Cook INLET BASIN...weeFIGURE7-9:BASE CASE ALL SUPPLY AGGREGATED...weeTABLE7-4:COOK INLET FIELD EXPECTED FUTURE GAS 'SUPPLY .. FIGURE 7-10:GUBIK BASIN..."FIGURE 7-11:NENANA BASIN EXPLORATION AREA ..FIGURE 7-12:YUKON FLATS OIL AND GAS PROSPECTS .. TABLE 7-5:COMPARISON OF NATURAL GAS BASINS..FIGURE A-1:PROJECTION OF Ot.DEMAND,SUPPLY,ANDgn In-State Gas Pipeline Supply Options Study Page 3 Executive Summary The primary objectives of this Study are to identify a cost-effective and timely plan for providing Alaskans with a long-term reduction and stabilization of energy costs,and to identify a solution for the Fairbanks community's PM 2.5 air quality issue. In the past two years,Interior Alaska has experienced extreme increases in the cost-of-living index,primarily due to volatile oil prices.High energy cost has made Interior Alaska's economic viability doubtful and has jeopardized the health and well-being of all of Alaska's present economy. This high energy cost has forced many Interior residents to supplement with,or switch to,wood or coal for space heating from fuel oil,negatively affecting Fairbanks'already poor air quality. Even without the increase in wood and coal burning,Fairbanks would not be able to reach the new PM 2.5 standards by 2010 without changes to its current predominant method of space heating.This Report gives a detailed view of the PM 2.5 issue,discusses consequences of non- attainment of EPA's air quality standards,and looks at options for meeting the standards. This Report also examines several probable alternative sources of energy for their affordability, timeliness,and effect on air quality.Several energy sources could effectively address one or two of these issues,but the Report finds that only a broad conversion to natural gas appears to solve all three. With the recognition that natural gas is the likely solution to affordability,timeliness,and air quality,this Report examines existing and potential in-state gas markets to gain an understanding of the volume of natural gas is currently consumed in-state,its potential markets, and how quickly those markets can be developed.The Report concludes that total in-state gas consumption for uses other than "industrial output”is now less than .14 Bcf/d and,if it is to develop an affordable delivery system for natural gas,Alaska must increase in-state natural gas use to more than .5 Bcf/d.Gas consumption outside the Southcentral region must be increased to make any in-state gas delivery project viable and,for Fairbanks,no plan will reduce area- wide particulate emissions and community energy cost without significant market penetration. The study provides a brief summary of published information on currently proposed in-state pipeline/supply options.They are: e Alaska Natural Gas Development Authority (ANGDA)Spur Line project Build 24”gas line from Southcentral to Delta Junction with an 8-inch gas line from Delta to Fairbanks. e ENSTAR Bullet Line project Build 24-inch gas line from North Slope to Southcentral Alaska. e Fairbanks Natural Gas (FNG)LNG from the North Slope to Fairbanks Construct LNG plant on the North Slope and truck LNG to Fairbanks. The project evaluation criteria include:design/construction schedules,projected capital costs and capacity of the proposed pipeline/delivery systems,and a review of available and potential gas basins that could supply these delivery systems. In-State Gas Pipeline Supply Options Study Page 4 The Study includes an examination of known and potential Alaska natural gas basins.As the various gas distribution proposals examined rely on different gas basins,the Study's project viability calculations include the distance of gas basins from markets and the likelihood that gas will be available from basins at the right time and in sufficient quantities. At least one project is dependent on the construction of an Alaska Highway gas pipeline,so the Report expresses an opinion on the likelinood of timely completion (2018)of the "TCAlaska”and "Denali-The Alaska Gas Pipeline LLC”pipelines and their plan to transport gas from the North Slope to Canadian and United States markets. The Report considers the claims of each project proponent,lists obstacles that each project must overcome to be successful,and gives conclusions about the three gas delivery projects. Finally,the Report makes recommendations on how Alaska might proceed to resolve its energy and localized air quality issues. Though made up predominately of Fairbanks community members,the Task Force chose to recommend a statewide energy solution,and not just a Fairbanks solution.All Alaskans have a critical need for timely and affordable energy,and it is within our collective power as Alaskans to use this issue as a catalyst for the start of a new chapter in the distribution of Alaska's wealth: ENERGY.The Task Force recommends that the State of Alaska lead this effort. 1.Study Objective The main objective of this Study is to identify a natural gas supply plan for Fairbanks that can be implemented as quickly as possible,and will provide a long-term reduction and stabilization of our community's energy costs and help ensure air quality compliance. To lower the high cost of energy,Fairbanks residents have been buming wood and coal for heat.However,air quality within urban areas of the Fairbanks North Star Borough (FNSB)has been declining due to increased particulate emissions.Switching existing fuel oil,coal,and wood heaters to natural gas would reduce airborne particulates and help the FNSB achieve and maintain compliance with the Federal air quality standards.This Report describes potential strategies that may become necessary within the next five years to comply with the Environmental Protection Agency's (EPA)latest PM 2.5 (particulate matter)air quality standards. Future dependence on oil as Interior Alaska's primary heating fuel will present significant risks: Energy cost volatility High cost of living Diminished economic opportunity Population decline Air quality noncompliance (EPA PM 2.5) This Study provides recommendations on how Fairbanks can lower its future cost of energy and meet air quality standards.A reliable supply of lower cost and cleaner burning natural gas could help solve both of these serious problems. In-State Gas Pipeline Supply Options Study ;Page 5 2.Study Scope This Study summarizes published information on the gas fields and proposed pipeline/supply options being planned for delivering natural gas and propane to Interior,rural and Southcentral Alaska,for the benefit of all Alaskans. We will evaluate each of the proposed gas pipeline and supply options,including their design/construction schedules,projected capital costs,and capacity of their gas supply and pipeline/supply system.We use this information to estimate when Fairbanks could receive gas from each proposed project and its price. The Report outlines the existing gas market in Southcentral Alaska and the current and projected gas market in the Fairbanks area.Penetration of the market by the new projects will depend on their delivered cost of natural gas compared to the price of existing gas reserves from the Cook Inlet fields and heating oil in Fairbanks. We also weigh the potential merits and risks to Fairbanks of the various gas pipeline and supply projects proposed for supplying Interior Alaska with natural gas as soon as possible.Because the proposed projects would provide future gas supplies to Southcentral Alaska,we discuss the political considerations and potential benefits provided throughout the State. We will recommend an action plan in this Report that we believe will provide a future low-cost and reliable source of natural gas for Interior and Southcentral Alaska. 3.Community Drivers In the past two years,Interior Alaska has experienced extreme increases in the cost-of-living index primarily due to volatile energy prices.These costs have not only worsened the quality of life for Interior Alaskans,they have made future economic growth doubtful and jeopardized the health and well-being of our current economy.In the past 30 days,the global price of crude oil has declined dramatically,giving Alaskans some relief from these staggering costs.However, while we appreciate the positive effect this turnabout has had on our community-and the household finances of energy consumers around the State-we recognize that the recent reduction in cost of energy will be brief (see Attachment 1,"Future Price of Energy'),and feel strongly that simply waiting for the next shoe to drop is not an acceptable solution. In 2006,the Fairbanks Economic Development Corporation (FEDC)formed the Cost of Energy - Task Force to rank energy options for the community based on the total energy consumed in Fairbanks (electric generation,space heating,and transportation).In 2007,the task force published the Fairbanks Energy Plan,which identified specific goals.It projected that a significant reduction in the community's energy cost and particulate emissions was possible through a combination of increased energy conservation and efficiency,and proactively seeking new energy alternatives.The State of Alaska and the Fairbanks North Star Borough have introduced an effective conservation and efficiency program that has helped reduce cost of living in our community.We believe this program should continue. But while conservation is effective and should be pursued,it alone will not sustain Alaska's economy.It is imperative that Alaska develop energy solutions that are both cost-effective and clean,and conducive to maintaining our communal health and well-being. In-State Gas Pipeline Supply Options Study 'Page 6 Achieving a healthy and affordable energy future,for itself and its fellow Alaskans,is Fairbanks' goal.Recognizing the probable negative ramifications of inaction-or wrong action-is what drives Fairbanks to pursue this goal. 4.FNSB Air Quality (PM 25) Monitoring of particulate levels in urban areas within the Fairbanks North Star Borough continues to show daily exceedances of Federal limits,particularly during periods of temperature inversions.This chapter describes the status of the FNSB's particulate emissions issue, 4.1 Particulate Matter (PM)2.5 Non-Attainment The Fairbanks area is surrounded by hills on three sides and is susceptible to severe surface- based temperature inversions during the winter that stratify cold air near the ground.Coupled with low wind speeds,pollutants in the air get trapped up to weeks at a time and concentrate resulting in periods of poor air quality.Particulate matter is one of those pollutants.Fine particles that are 2.5 micrometers in diameter and smaller (PM 2.5)are unhealthy to breathe and have been associated with serious lung and heart problems.These particles are a mixture of microscopic solids and liquid droplets suspended in air.Sources of fine particles include all types of combustion activities (motor vehicles,power plants,wood burning,etc.)and certain industrial processes.Cold weather (near 0 degrees F and below)seems to increase the PM 2.5 levels in the Fairbanks area during temperature inversions. In 1997,the EPA issued standards for PM 2.5 based on health studies and extensive peer review.The annual standard of 15 micrograms per cubic meter and 24-hour standard of 65 micrograms per cubic meter (ug/m3)is based on a three-year average of annual mean PM 2.5 concentrations.In September 2006,the EPA issued revised national air quality standards for PM 2.5.The daily PM 2.5 particle standard has been reduced from 65 to 35 pg/m3 of air. In March 2007,EPA issued a rule defining requirements for states to clean the air in areas with levels of fine particle pollution that do not meet national air quality standards.EPA designates an area as "non-attainment'if it violates the fine particle standards over a three-year period. Once an area is designated as non-attainment,the Clean Air Act requires a state to submit an implementation plan to EPA within three years.This plan must include enforceable measures to reduce air pollutant emissions that form the fine particles in the atmosphere.The plan must also provide enforceable steps to attain the PM 2.5 standards and show how it will make reasonable progress toward meeting them. States must meet the new PM 2.5 standard by 2010.In their 2008 implementation plans,states may propose an attainment date extension for up to five years.Those areas for which EPA approves an extension must achieve clean air as soon as possible,but no later than 2015. In August 2007,the Alaska Dept.of Environmental Conservation (ADEC)published "Alaska's 2008 Air Monitoring Network Program.”This document included the following statements concerning Fairbanks: e "Fairbanks had consistently experienced the highest PM 2.5 values measured in the State.” In-State Gas Pipeline Supply Options Study Page 7 "Based on winter PM 2.5 levels,Fairbanks had been flirting with exceeding the annual fine particulate standard (set at 15 ug/sm3)for the past seven years.If [they are]exceeded, Fairbanks will need to control year-round PM pollution.” "To address the needs of an Alaska PM 2.5 State Implementation Plan (SIP),the Fairbanks North Star Borough is expanding its monitoring network to better identify the magnitude, extent,and source of its winter PM 2.5 problems.This effort will see the addition of between three and five new monitoring sites operated during the winter months.” "The 2007 PM 2.5 network so far only monitored the fine particles at the State Office Building.” 4.1.4 FNSB Non-Attainment Boundary (PM 2.5) In December 2007,ADEC sent a letter to EPA recommending that,based on the past three years of ambient air monitoring data,EPA designate all areas of the State in attainment with the annual PM 2.5 standard of 15 pg/m3.The letter also stated that Fairbanks was the only Alaska community that had exceeded EPA's new 35 ug/m3 (24-hour)standard.Enclosed with the letter was supporting information that included a recommended boundary for a Fairbanks PM 2.5 (24- hour)non-attainment area.Following are excerpts from that document concerning the proposed PM 2.5 non-attainment boundary: "Ambient air monitoring has been conducted at one site in downtown Fairbanks since the PM 2.5 network was established in 1999.While this site does represent the level of fine particulates in the downtown area,there is nothing to confirm that PM 2.5 concentrations exceed State and Federal fine particulate standards outside of the urban center.” "EPA recommends that states consider nine factors in making non-attainment boundary recommendations.These nine factors include:emission data,air quality data,population density and degree of urbanization (including commercial development),traffic and commuting patterns,growth rates and patterns,meteorology (weatherAransport patterns), geographyAopography (mountain ranges or other air basin boundaries),jurisdictional boundaries (e.g.counties,air districts,reservations,metropolitan planning organizations [MPOs)]),and level of control of emission sources.” "Based on a number of these factors,the department (ADEC),in consultation with the Fairbanks North Star Borough,has developed a recommended boundary for a PM 2.5non- attainment area in Fairbanks.The proposed boundary captures the air shed most likely contributing to the exceedances in Fairbanks resulting in non-attainment of the health standard based on existing monitoring data and other factors listed above.” "Because there is only one monitoring site in Fairbanks,the monitoring data and source characterization work derived from that site is most likely not representative of the source contributions throughout the entire area.” "At this time,no monitoring data exist for the city of North Pole or other residential areas in the outlying valleys to the north of Fairbanks.At this time,there is insufficient information to suggest that North Pole or these other outlying populated areas have an air quality problem or are significantly contributing to the air quality violations occurring in downtown Fairbanks. Furthermore,some of the outlying populated areas are located at higher levels that are frequently above the inversion layer.Therefore,PM 2.5 concentrations are most likely lower than in downtown Fairbanks because areas above the inversion experience good exchange In-State Gas Pipeline Supply Options Study Page 8 with air masses aloft.For these reasons,they have been excluded from the proposed boundary.” e "As supplemental information and data are collected over the next several years,this boundary could be further refined." Figure 4-1 shows a map of the PM 2.5 non-attainment boundary originally proposed by ADEC and FNSB. Figure 4-1:FNSB's Proposed PM 2.5 Non-Attainment Boundary ee Cael Baer as.-3 ai asAyome Fairbanks nonattaione nt cmfoiaaabe In 2007,FNSB installed a particle monitor at Nordale School and uses a mobile sniffer,known as the RAMS trailer,to gather air samples throughout the FNSB. In April 2008,ADEC issued an updated "State Air Quality Control Plan.”This document included the following statements concerning PM 2.5 emissions: In-State Gas Pipeline Supply Options Study Page 9 e "In arecent rulemaking with an effective date of December 18,2006,EPA revised the level of the 24-hour PM 2.5 standard from 65 to 35 ug/m3.A review of monitoring data collected in Fairbanks in recent years shows summer values are generally low,approximately 7 yg/m3 (24-hour average),except when smoke from wildfires is transported into the downtown area (i.e.,the location of the borough's PM 2.5 monitor).When this occurs, concentrations can become quite high (many multiples of the recently adopted 35 ug/m3 standard).Concentrations resulting from these conditions,however,can qualify as exceptional events.Winter values average approximately 23 pg/m3 (24-hour average),but episodically can exceed 50-60 Ug/m3.” e "The entire State of Alaska is currently classified as in attainment of the PM 2.5 standard; however,barring a substantial change in wintertime concentrations,it is likely the State will recommend to EPA that Fairbanks be designated non-attainment of the revised 24-hour PM 2.5 standard in 2008/2009.” During the past three years,the Fairbanks area has exceeded the 2006 revised EPA PM 2.5 (24-hour)standard of 35 pg/n3 numerous days during the winter.Figure 4-2 shows the number of days the PM 2.5 (24-hour)standard was exceeded during the past five calendar years.The graph in Figure 4-3 shows the daily PM 2.5 (24-hour)levels in Fairbanks during the four winter months of November 2005 through February 2006. Figure 4-2:PM 2.5 Exceedances (2003-2008) Five Winter Comparison -Number of Daily Values Exceeding New EPAPM2.5 Standard downtown Fairbanks,AK wp >=35 ug/m3 new EPA Standard * « a 3 al * 2a EE] z Viinter Winter Woiter Virler VWinter 2083-04 2004-65 2008-95 2008-07 2007-08 Viinter (November,December,January,February) Figure 4-3:Fairbanks Daily PM 2.5 Levels (Winter 2005-2006) In-State Gas Pipeline Supply Options Study Page 10 Fine Particulate Matter -Downtown Fairbanks November 1,2005 through February 28,2006 70 69 50 .24 ler standardforPil,=35Poly40$s * m3 een Serr reres fore |ere senrrene |fenre ee |Seeeees0)Becerra |pennedF30-J2 7]= 20 40 4 lI ul li HI ||||||ul unl || SSSS 888 SERS SERE RS RES LESS SES SS ESSE SEER SSERSESESE SESS ERERER ERESS8SSLCLLELZAGKRAESRSSESELLECSARLGRSSSSSSCLLSRRSKSSSESLSBELLESREASSEESTPESEPESETEASAANAASAANSSANSESSSSSSSESSSSSSRAASANSSAASSSSS In August 2008,EPA sent a letter notifying the State of its intent to designate a portion of the Fairbanks North Star Borough (FNSB)as non-attainment and to modify Alaska's recommended FNSB non-attainment boundary.EPA encouraged the State to submit any additional information that EPA should consider concerning the FNSB PM 2.5 non-attainment boundary before October 20,2008.Figure 4-4 shows EPA's proposed boundary.It encompasses a large area of the borough that has few or no people,such as the Tanana Flats.EPA plans to publish a notice in the Federal Register to solicit public comments on its decision and make final designation decisions for the 2006 PM 2.5 (24-hour)standard by December 18,2008. In-State Gas Pipeline Supply Options Study Page 11 Figure 4-4:EPA's Proposed PM 2.5 Non-Attainment Boundary ee.my FAIRBANKS NORTH STAR BOROUGH ns :"ae esaede!as re mcr ree ip rai,is ae. iin In October 2008,the FNSB proposed a smaller PM 2.5 (24-hour)non-attainment boundary to EPA that is shown in Figure 4-5.An EPA decision on the non-attainment boundary is pending. In-State Gas Pipeline Supply Options Study Page 12 Figure 4-5:FNSB's Adjusted PM 2.5 Non-Attainment Boundary| aaa Woe ygowdAfwoo cafk . Mie ¥"= ae,7 &he ¥C wr»Ma +|FARBANKS NORTH STAR DOROUGI: Population Censity -2000 CensusPersonsPerSquareMile [J iss propcess Pe eran acted to UFO Prepared by Fairbenia hort:Star BoroughGepertmentofCommuntyPemning=TDOxtoamr10.2006 4.2 PM 2.5 Particle Analysis ADEC and FNSB have analyzed the samples collected in the ambient air monitors and identified possible sources of the PM 2.5 particles.They found that the winter samples contained about 40 to 55 percent of the fine PM 2.5 particles made of secondary sulfate and nitrate aerosols.Most of the remaining aerosol was contributed equally from wood buming emissions and an unknown zinc-related factor.Trace amounts were also identified as sea salt, motor vehicle emissions,and soil.Figure 4-6 summarizes these results. In-State Gas Pipeline Supply Options Study Page 13 Figure 4-6:PM 2.5 Particle Analysis Results Simm Sez Sh: ommmme Secoa dry (SullsteeNizate)Oo bers C=Moros Velie :Co Wood BursicgmameSo: Gea 22 Factor i pe Me "e i$-te bin =233z :use ioe lg TLéa re thas 11.33 32.6 . ™932 Els 9.4 "73 -10 ef}t St$125.82 SITE SY Foc Sat at ot ot nth ageetohawe¥RS)ponwyRETNyreeMoOea Dare Sulfite and Nitrate Aerosols:The source of the sulfur and nitrate aerosals is most likely burning fuels that contain sulfur.Fairbanks vehicles burn significant amounts of gasoline and diesel fuel; however,the sulfur content of both fuels has been reduced dramatically in recent years.Low-sulfur diesel fuel contains 0.007 percent sulfur by weight.The sulfur content of fuel oil used for building heating contains about 0.22 percent sulfur.Although there are numerous sources in Fairbanks that burn fuel containing sulfur,the distillate fuel oils used in space heating could be a dominant source of the atmospheric sulfite and nitrate aerosols in Fairbanks during the winter. Wood Burning Emissions:Heating fuel oil prices in Alaska have increased significantly during the past four years,and data from ADEC-sponsored building heating surveys show that more households and businesses have installed supplemental wood-burning heaters.The EPA estimates that wood stoves emit more pollutants than oil-fired furnaces-generally 30 to 250 times more particulates on a heat-equivalent basis. Zinc-based Emissions:The source of the zinc found in the Fairbanks PM 2.5 particles is unknown at this time.Possible sources include burning of waste lubricating oils,motor vehicles burning lube oil,or distant sources of zinc mining and ore handling.Zinc is widely used as an additive in lubricating oils for diesel engines and,in lower concentrations,for gasoline-powered engines. 4.2.1 Expanded PM 2.5 Sampling Program Starting in 2007,the FNSB expanded monitoring to determine the extent of the elevated PM 2.5 emissions.This effort continued last winter (2007-08)with three new fixed monitoring sites,a re- locatable trailer,and a mobile monitor.One of the fixed sites was placed in the Hamilton Acres area to characterize the PM 2.5 in a neighborhood setting.The FNSB placed another fixed site downtown near the State Office Building,to support those monitors with new types of monitors In-State Gas Pipeline Supply Options Study Page 14 that will help differentiate the sources of the PM downtown such as mobile sources.The third fixed site is on south Peger Road and monitors the roadway contributions and the effect of mobile sources such as cars and commercial vehicles. The trailer was placed in eleven different locations in and around the Fairbanks and North Pole areas,including varying altitudes to better assess the spatial extent and inversion/particulate layer height for PM 2.5 particles. The mobile monitor drove extensively through neighborhoods and industrial areas throughout the Fairbanks and North Pole area as well as Goldstream Valley.FNSB is using these data to assess the spatial extent as well as the local effects of hot spots (outdoor wood boilers [OWBs], poorly running woodstoves,and high-emitting vehicles). During 2008,the FNSB Air Quality Department refined and expanded its studies further with a new fixed site in North Pole and the addition of new "speciation”monitors that provide data on the chemical types within the collected PM particles.These new instruments will help apportion the source mixture of the PM and indicate the best way to reduce and maintain PM emissions in the future.The FNSB has also expanded its meteorological monitoring to help assess any transport of PM from outside the downtown area.New meteorological measuring equipment has been set up at the South Peger and Hamilton Acres sites,and will soon operate at the North Pole site. These new "speciation”monitors will provide data to be input into the EPA's UNMIX model as well as a Chemical Mass Balance model to help differentiate between mobile source contributions and space heating.In addition to those analyses,the information from those monitors will be analyzed for key tracers of wood burning.This should allow us to separate the wood burning sources from the rest of the sources. A better understanding of the Fairbanks basin microclimate and the meteorological patterns thatcausesevereinversionsisnecessarysowecanpreventexceedancesofthePM2.5 by applying cost-effective emission reduction practices. 4.33 PM2.5 Standard Non-Compliance Consequences Areas that EPA classifies as non-attainment are subject to a Federal measure known as "transportation conformity.”It requires local transportation and air quality officials to coordinate planning to ensure transportation projects (road construction,etc.)do not hinder an area's ability to achieve and maintain clean air standards.Non-attainment areas also become subject to "new source review”requirements,which is a Federal permitting program designed to ensure that pollution from new and modified industrial facilities does not impede progress toward clean air. Some of the potential negative consequences for the Fairbanks North Star Borough of not meeting and maintaining EPA's PM 2.5 (24-hour)standard could include the following: e Unhealthy air quality during winter inversion periods leading to increased health care costs for residents,also deterring future population growth in the Fairbanks area and discouraging new businesses from locating in the Interior e Loss of Federal highway funds along with other Federal funding streams In-State Gas Pipeline Supply Options Study .Page 15 e Denials on submitted projects to Federal review due to continuation of non-attainment days after program implementation e Reduced military staffing at Fort Wainwright and Eielson Air Force Base 4.3.1 Fairbanks PM 2.5 Implementation Plan The FNSB,City of Fairbanks,City of North Pole,ADEC,and Alaska Department of Transportation and Public Facilities (DOT&PF)are working together to develop an implementation plan that will achieve and maintain the current EPA standards by reducing PM 2.5 air pollutant emissions by 2014.Population growth and increased fuel combustion in the Fairbanks area are most likely responsible for the area's PM 2.5 violations during winter months. Following are some possible methods of reducing PM 2.5 (24-hour)levels during peak winter inversion periods: Reduce Open Burn Periods:The FNSB currently bans open burning from November 1 through the last day of February in areas designated as Urban,Urban Preferred Commercial, Light or Heavy Industrial,or Perimeter area,with campfires as an exception.The length of the _winter ban could increase and the affected area could be expanded to encompass the PM 2.5 boundary. Reduce Distillate Fuel Emissions:The following could reduce particulate emissions from existing fuel oil-fired heating systems: e Switch to a lower-sulfur fuel for all oil-fired building heating systems in the Fairbanks urban areas. e Introduce annually required inspections and tune-ups on oil-fired furnaces similar to the I/M program to ensure optimum burning efficiency and low particulate emissions. e Collaborate with other non-attainment northern tier communities across the U.S.to pursue subsidies,exceptions,waivers,retrofits,new regulatory requirements for manufacturers, etc.,from Federal agencies.For example,as part of the process of reaching attainment for carbon monoxide (CO)standards in Alaska,Alaskan research conducted in the early 1980s documented that motor vehicle emissions reductions for CO were not achieved at cold temperatures because EPA tested vehicle emissions at room temperature ranges only. Efforts by Alaska and other local and state governments were successful in getting Congress to require EPA to test vehicular emissions at 20 degrees F to make sure auto manufacturers were improving combustion efficiency and the performance of pollution control devices to reduce CO emissions during cold starts.Asimilar effort could determine if the full benefits of the motor vehicle pollution control program are accrued at low temperatures for PM 2.5.Control of poorly tuned or broken vehicles may be necessary to address the hydrocarbon emissions that increase dramatically with low temperatures. Reduce Wood Stove Emissions:|nvestigate methods of improving or restricting wood stove operation during winter inversion periods.EPA has published information on the efficiency and PM 2.5 emission rates of various wood stoves,summarized in the following two tables: In-State Gas Pipeline Supply Options Study Page 16 Table 4-1:Efficiencies by Stove Type Appliance Type Efficiency Conventional Cordwood Stove 34% Non-catalytic Cordwood Stove 63% Catalytic Cordwood Stove 63% Pellet Stove 78% Table 4-2:Cordwood and Pellet Stove PM 2.5 Emission Factors ;'T Conventional |Catalytic TT Non .Pellet Stove Woodstove Certified catalytic Exempt Certified ©Obrion)Woodstove Certified (b/ton)(Ib/ton) ;(Ib'ton)Woodstove (Ib'ton) AP-42 Emission 30.6 16.2 14.6 8.8 42 Factors According to EPA,certified pellet stoves had the highest fuel efficiency and the lowest PM 2.5 emission rates.Conventional wood stoves were much less efficient with the highest PM 2.5 emission rates. Following are potential wood stove strategies that could help reduce their PM 2.5 emissions: Restrict Wood Stoves:Restrict the installation and use of wood-burning or waste-oil heating appliances during winter inversions.This would require more information to quantify their contribution to PM 2.5 emissions in the Fairbanks and surrounding area during winter. Wood Stove Buy-Out:Rapidly develop a trade-out of older wood stoves through a locally bonded,State,or Federally funded program that provides affordable upgrading for residents who own older or unapproved new simple wood heaters or the non-EPA approved wood boilers. Through local education,it would create an incentive to trade out rather than not comply.A successful trade-out program in Libby,Montana,could be used as a model. Retrofit Wood Stoves:Investigate possible improvements in modes of operation or equipment modifications that could retrofit existing wood stoves to produce fewer PM 2.5 emissions. Encourage Dry Wood Use:Discourage late season harvesting of green standing trees.Wet wood burns inefficiently and could increase particulate emissions.The FNSB could work with the State to provide residents access to supplies of dry seasoned firewood. Reduce Waste Oil Heater Emissions:Consider restricting the use of waste oil burners during winter inversions.More information will be needed to verify that burning waste oil is the actual source of zinc-based PM 2.5 emissions in the area during the winter.Investigate whether using micron filtration can remove zinc compounds and unwanted impurities from waste oils before they are burned in the heaters. In-State Gas Pipeline Supply Options Study Page 17 Expand District Heating:Aurora Energy provides district heat to downtown Fairbanks through buried steam and hot water heating systems from its power plant.Expanding the existing district steam and hot water heating systems could replace individual oil-fired furnaces throughout the downtown area and surrounding subdivisions and lower PM 2.5 emission levels. Expand Natural Gas Use:Switch existing residential and commercial oil-fired building heaters in the urban area to natural gas to reduce PM 2.5 emission levels.Fairbanks Natural Gas (FNG) has been expanding its buried distribution system and is providing heat to many Fairbanks-area buildings. In the short term (2008-2010),we expect that implementing a combination of the methods listed above will help the Fairbanks region move toward achieving the new EPA PM 2.5 (24-hour) emission standard.We also believe that switching existing building heaters to natural gas and expanding district heat would provide the FNSB a long term solution for achieving and maintaining its air quality in compliance with EPA's PM 2.5 standards. 5.Alternatives for Energy Though this Report's primary focus is on the use of in-state natural gas,a brief review of other alternative energy sources is appropriate.Alternative energy options are likely to be considered by individual homeowners.The most obvious is residential space heating with wood or coal stoves,which has already increased substantially in Fairbanks.These are,however,causing increased PM 2.5 air pollution problems and will require replacement of inefficient units or improvement of smoke emissions if they are to address one problem without exacerbating the other.They also cannot be considered a 50-year solution until forestry and horticultural techniques are devised and implemented on a commercial scale that might ensure sustainable cultivation of dedicated biomass-for-energy crops. Solar panels (both photo-voltaic and solar-hydronic)for Interior Alaska are in the trial stage at homes,businesses,and the Cold Climate Housing Research Center.The cost of solar panel production must drop by a factor of at least five to be economically competitive with other potential energy sources.. Increased wind power may be a good prospect in some areas,if priced competitively,but cannot replace more than 20 percent of total electrical needs because of base load requirements and the unpredictability of wind.In some Alaska locations,wind-generated electricity can help heat homes and reduce overall diesel fuel usage but,like solar,we cannot rely on it as a sole solution. Because of the above constraints,the introduction of alternative energy options will be incremental and evolutionary,and will not solve the energy shortages of Alaskans in the near to medium term (2014-2034).We believe from the 100-year perspective,however,electricity from hydroelectric,geothermal,and possibly nuclear reactors will heat residences and commercial buildings,and power transport vehicles.Other alternatives may also contribute,depending on the economics,but remain outside the bounds of this analysis. In this section we discuss four major energy alternative scenarios (here defined as energy sources other than those predominating in a particular locality,such as Cook Inlet gas in Southcentral or oil in the Interior),which assumes that Alaska natural gas is not made available In-State Gas Pipeline Supply Options Study Page 18 to Anchorage and Fairbanks by 2015.The alternatives include a baseline "Do Nothing Scenario,”a "Coal-Only Scenario,”a "Susitna Hydroelectric Dam Scenario”and the "Nuclear Option.”These are considered conceptual forecasts,assuming that each one is the only project undertaken.In that way,each alternative scenario can be compared with the severa!existing in- state gas distribution proposals discussed elsewhere in this Report. For each of the four alternative options discussed below,a brief analysis of strengths, weaknesses,opportunities,and threats (SWOT)is provided. 5.1 Do-Nothing Scenario The Do-Nothing Scenario for energy in Alaska is we do not build a gas line or develop a transportation system to deliver gas.The consequences of this policy are enormous. The proven natural gas supply available in the Southcentral region is rapidly depleting,with some users already facing an unavailability of gas for commercial heating in the winter of 2008- 09.Barring discovery of large quantities of gas in Cook Inlet,export of liquid natural gas (LNG) from Cook Inlet could be in jeopardy as early as 2011.By 2015,the gas supply from existing Cook Inlet reservoirs will be clearly inadequate even for Southcentral's needs.The quantity of electricity generated by Cook Inlet gas will not meet demand,and the heating of buildings and residences will be greatly impacted.The military bases (Fort Richardson and Elmendorf Air Force Base)will also be threatened with loss of gas for heating. 5.1.1.Do-Nothing Scenario:Electricity If the 50 MW Healy Clean Coal Power Plant (HCCP)is in operation by 2011,it will not be large enough to compensate for the loss of gas-fired electricity in Southcentral. If a natural gas pipeline is not built by 2015,it will be necessary to discover,develop,and connect new gas reserves in the Southcentral region or begin importing LNG into Southcentral from outside Alaska.Generally,the probability of substantial gas discoveries in the Southcentral region is lower than the probability of successful importation of LNG,possibly at a high price and including additional investment in any necessary infrastructure. Anchorage and Fairbanks will start to have age-related breakdowns of their existing 35-to 50- year-old power plants in the near future.They will either need to have these plants retrofitted with modern,new equipment,or build new coal-fired power plants of conventional design. Across America,the construction of utility-sized coal-fired power plants has been deferred due to possible enactment of governmental regulations on carbon dioxide emissions from new plants of this type.The extra costs of carbon dioxide sequestration are significant.Construction of a coal-fired steam plant from conception to completion takes at least ten years.This could put the Railbelt in an electric power crisis by the year 2015. 5.1.2 Do-Nothing Scenario:Heat In this scenario,the majority of Fairbanks buildings continue to use fuel oil for heat.Fairbanks Natural Gas (FNG),which is considering a proposal to build a liquefied natural gas plant on the North Slope to continue serving its existing customer,does not do so and its customers must seek other space heating methods. In-State Gas Pipeline Supply Options Study Page 19 People will increasingly use wood and coal as a self-reliant way to heat homes-a reversion to techniques Interior residents used in the last century and have pursued in growing numbers in recent years. In the absence of North Slope gas,the next most likely source of supply for Southcentral is imported LNG.Natural gas prices,compounded by the expense of liquefaction and transportation,have traditionally followed increases in fuel oil prices.This option for satisfying Southcentral gas demand will be expensive and it is likely under this scenario that many residents will,out of choice or necessity,pursue a similar course as their neighbors in Interior Alaska:installing wood or coal stoves for supplemental or primary heating. A large natural gas pipeline or a smaller "bullet line”through Fairbanks would alleviate this situation,but a large Alaska Highway pipeline cannot be put into place until 2018 or later,and may not happen at all if unconventional natural gas from shale in the Lower 48 is sufficient and economic enough to meet demand Lower 48 markets.Even if the Alaska Highway gas line is built,a separate spur line from Delta Junction to Anchorage will be required to supply Southcentral's gas needs:something that simply cannot happen by 2015 because the large line cannot be built by then. 5.1.3.Do-Nothing Scenario:Transportation Fuel In this scenario,there will be no change in the use of the gasoline and diesel fuel from the Fairbanks refineries,or from the Kenai refinery,and the Railbelt will continue to be supplied with refined fuel products at spot prices.When the Trans-Alaska Pipeline or the Flint Hills Refinery shut down,however,the fuels produced in Fairbanks will be replaced with products imported at spot prices from Lower 48 or foreign refineries,such as those in Japan,Korea,or Singapore. The Alaska Railroad will transport the fuels daily and the transport charges will be added to the fuel cost.The Golden Valley Electric Association will buy naphtha or other appropriate products from sources outside of Alaska when this happens,paying the spot prices prevailing at that time. 5.14 Do-Nothing Scenario:SWOT Analysis The advantage ofthe baseline (in-state gas line not built)option is that no Federal,State or private decisions are necessary,there would be no new energy investments,and no new State resources would need to be marshaled.Residential and small business-sized coal and/or wood burners would be used,resulting in significant air pollution.Existing coal-fired power plants would be repaired or replaced as they approach the end of their life. One disadvantage is that to continue the use of their current electric generation equipment, Alaska's large utilities that now burn natural gas would have to purchase imported supplies of foreign LNG or make the substantial investments necessary to convert their power generation to other fuel technologies. Another disadvantage of the baseline option is that it results in high energy costs for Alaskan residential and commercial users.It would probably lead to a significant reduction in Alaska's population,job opportunities,and other economic ventures.Even in Alaska's largest city,the retrofitting of the community's infrastructure to accommodate coal or fuel oil heating would be costly and Anchorage's economy would suffer severely. In-State Gas Pipeline Supply Options Study Page 20 9.2 Coal-Only Scenario Coal has heated homes for centuries,and produced electricity since the 1880s.Although it was initially the fuel for railroads,it did not adapt well to highway transportation,and its transportation use ceased with the advent of oil.Many believe the world is departing from the "Age of Coal,”is nearing the end of expansion of the "Age of Oil,”and is just entering the growth portion of the "Age of Gas.”The widespread availability of gas to the consumers of the world will accelerate this trend,but coal is still economical,and coal resources are still abundant.The "Age of Coal”is not over. In the Coal-Only Scenario,we are assuming coal is the cheapest energy alternative,and that gas and conventional crude oil are not available at a reasonable price,therefore more and more residents and businesses burn coal for heat.Coal will generate electricity and may be used to produce synthetic hydrocarbon fuels for use in transportation vehicles and for home heating throughout the State,using existing infrastructure. Coal costs have been less volatile over the years when compared to other hydrocarbons.Due to lower transportation costs,coalis cheaper than any other fuel source (including wood)when used close to the mine mouth. 5.2.1 Coal-Only Scenario:Electric Conventional coal-fired steam plants operate today in Fairbanks,Healy,and Clear.They are of traditional design,were built 30 to 40 years ago and are nearing the end of their useful lives. Nevertheless,new coal-fired steam plants are under construction today,particularly in foreign countries,though they may come with serious air pollution challenges. At the end of the last century,the Healy Clean Coal Plant (HCCP)was built as an experiment to utilize waste coal,at very low prices,and at the same time deliver a clean exhaust stream.It can be renovated in 12 to 18 months to produce 50 megawatts (MVV),but may require significant ongoing maintenance.We should consider this plant as an option.Negotiations continue.. One possibility for meeting the Railbelt's electric power needs is to construct a modern, regional-sized (600 MW)coal-fired steam plant to generate electricity.This will be economical, although it will need to be equipped with the best-available air pollution control technology. Some of this power,from 75 to 140 MW,could be sold in Fairbanks through the existing Railbelt intertie.If we built coal plants within 10 miles of populated communities,it might be possible to install district heating throughout many of those communities and thereby provide heat to commercial buildings as well as residences. 5.2.2 Coal-Only Scenario:Heat Electric heat is one option available under this scenario for Railbelt communities,replacing the existing gas-combustion heating in Anchorage and the oil-combustion heating in Fairbanks.If the cost of electricity is not competitive with these fuels,individual homeowners may continue to consider installing coal-fired stoves and boilers,as they currently do in the Interior.Generally, the electric cost will depend on the capital cost of the coal-fired power plant.The provision of coal for heating in remote villages of Alaska is still problematic,and may be impractical unless coal deposits near villages can be identified.In the greater Fairbanks area,heating with coal- fired stoves and boilers becomes economically attractive when the price of heating fuel approaches $3/gallon. In-State Gas Pipeline Supply Options Study Page 21 5.2.3 CoatOnly Scenario:Transportation Fuel One option for addressing transportation fuel needs in the Coal-Only Scenario is a Coal-to- Liquids (CTL)Plant.This would produce a hydrocarbon liquid with the same specification as Jet-A:a fuel that can serve as road diesel,arctic grade heating oil,and aircraft jet fuel.This fuel has the added advantage of low sulfur content,exceeding all existing specifications.Such a plant,producing 40,000 barrels per day (bbi/d)of liquid fuels,is in the early design stage for Fairbanks.This plant could provide liquid fuel for heating and electricity in rural Alaska,as well as for some portion of the Railbelt's liquid fuels market.Of the two possible plant designs,the coal-only configuration is a plant fed entirely with coal at the rate of 34,392 tons/day,delivered by rail from the coal mine at Healy.The cost of the plant (using recent and inflated construction costs)is estimated at $7.45 billion for the coa-only version,with a broad range of +/-40 percent.The Coal-To-Liquids Plant could provide hot water for district heating for communities within 20 miles. This plant will produce heating oil and transportation fuels at an estimated finished product priceof$426 /bbl,or $3/gallon.This is below the crude oil prices shown in Attachment 1,beginning in 2014,the year of completion of the proposed Coal-To-Liquids plant. 5.24 Coal-Only Scenario:SWOT Analysis One advantage of coal is that it is relatively inexpensive and will likely remain so into the future, independent of oil prices.Alaska coal is also abundant,and reserves are expected to last 400 years,with many Railbelt communities already having access to a large,established,and operational coal reserve by rail.Finally,coal can be burned directly for heating,or converted into electricity and/or liquid hydrocarbon fuels.Therefore,coal appears ready to provide an economic and versatile energy source to Alaska. A current concern with industrial-scale coal use is carbon dioxide generation,an issue that must be addressed for any project proposal to succeed. 5.3 Susitna Hydroelectric Dam Scenario The Susitna Hydroelectric Dam Project,as proposed in the Federal Energy Regulatory Commission (FERC)License Application in the 1980s,consists of two dams on the Susitna River about 180 miles north of Anchorage.The Watana portion (an earth-and rock-filled dam creating a major water storage reservoir approximately 48 miles long)would be built first and produce up to 1110 MW of capacity.The second portion would be a thin-arched-concrete dam at Devil Canyon,downstream from Watana.The Devil Canyon portion of the project would create a reservoir 26 miles long and add an additional 680 MW of capacity to the system. Together,the two dams are estimated to have a combined maximum electric generating capacity of 1,790 MW,and could provide abundant,clean,and renewable electricity for more than 100 years. In 2008,the Alaska Legislature appropriated $5 million to review and update plans for the Susitna Dam project.Details of the water flow into the reservoirs and the total electric energy to be expected each year are currently under review,as are the economics and potential environmental impacts of project construction.However,it is clear that the electricity from Susitna,either from the Watana project alone or from the pair of dam projects,would be cheaper than any possible fossil fuel electric generation.If the entire project were completed, In-State Gas Pipeline Supply Options Study Page 22 the Susitna Dam would also provide power well in excess of the entire present electrical needs of the Railbelt's cities and villages. This project could result in the lowest-cost electricity of the alternative options this Report analyzes,but it would not affect residential heating or transportation-the two other factors in Alaska energy consumption-until at least the year 2025,when there will likely be an abundance of electrically driven vehicles and more electrically heated homes and buildings.If Susitna is built,however,the retrofitting of buildings in the Railbelt for electrical heating will accelerate,leading to more available natural gas for export at world prices. Permitting of Susitna will be extensive because of the many regulations and FERC processes, but actual construction will be of normal duration.If the permitting process began in 2009,the project could conceivably be complete by 2025. 5.3.1 Susitna Hydroelectric Dam Scenario:SWOT Analysis The generation of electricity by hydropower is the lowest-cost form of energy.It is also an air pollution-free energy source that is renewable and does not contribute to global warming or greenhouse gases. A disadvantage of hydroelectric projects is that they have long lead times and thus cannot address Alaska's energy needs in a 10-year period.Also,because the Susitna project will have a high up-front capital cost,there is the possibility that it may again prove susceptible to market forces outside Alaska or State budgetary challenges. In spite of this,Federal or State governments or a consortium usually undertake large hydroelectric projects in the public interest,and have proven them successful in reducing electric costs and creating/stimulating regional economies.Abundant,clean,low-cost Susitna power would create an incentive to gradually convert heating and transportation vehicles to electricity.This would free Alaska's oil and gas reserves for other uses such as increased export,where the State could maximize revenue from the sale of oil and gas without negatively impacting Alaskan energy consumers.Alaskans would also benefit because their energy costs would be locked in at the time of construction,isolating them from escalations of world oil and gas prices during the entire (100+-year)life of the project. 5.4 A Nuclear Option? While not a ten-year solution,nuclear power may be feasible in the long term. Construction of a large nuclear power plant,or a series of small (10 MW to 20 MW)power plants,could create new electric power in the State.While a large nuclear facility can be cheaper than numerous small reactors due to economies of scale,new technology is making small-sized nuclear reactors more cost competitive.Small reactors have less risk of leakage, could be quicker to set up as needed,and will last for 20 to 30 years.A possible strategy is to buy a small nuclear reactor as a demonstration plant. One noteworthy difference between hydropower and nuclear is the ability of the former to match peak needs,and to save energy for those times of high demand.Conversely,nuclear power isatfullpowerallthetime,and normally is a low-cost base load generator embedded in a larger grid with other types of energy sources. In-State Gas Pipeline Supply Options Study Page 23 Prior to the onset of the current recession,large (500 MW to 1000 MVV)nuclear power plants escalated in price due to high labor costs and an increased world demand.Nuclear power also suffers from negative public perception.However,if electrical demand in the Railbelt exceeds Susitna hydropower's output capacity in the future,regional or local consideration of nuclear power may be renewed. 6.In-State Natural Gas Market This section of the Study estimates the potential demand for natural gas in the Fairbanks area. It also describes Southcentral natural gas demand.The estimated gas market takes into account the potential industrial,commercial,and residential demand for the years 2009 through 2016.This time period was chosen because supply options may be available before a "large” 48-inch Alaska Highway Pipeline (TransCanada or Denali)becomes a reality.Large industrial loads such as the Coal/Gas-to-Liquids Project,LNG export,and Agrium fertilizer production could also affect the in-state gas pipeline designs.© 6.1.Interior Alaska Gas Market The Fairbanks North Star Borough (FNSB)represents one of the greatest potential natural gas markets in Alaska.Fairbanks Natural Gas (FNG)began service to the area in 1998 through truck transport of LNG from Wasilla to Fairbanks.Currently FNG supplies approximately 1,100 residential and commercial customers. The Interior natural gas market is made up of industrial,commercial,and residential demand. While Rural village markets may not use natural gas directly,they could benefit from the use of propane,which could become available from gas conditioning facilities meant to service either the in-state distribution system or an Alaska Highway pipeline.Table 6-1 below details the existing gas market in Fairbanks. Table 6-1:Fairbanks Natural Gas Sales 2007 2008 Volume Sold Mcf*Mcf GVEA 0 0 Flint Hills 0 0 Petro Star 0 0 Residential Customers 56,286 63,515 Small Commercial Customers 373,322 431,998 Large Commercial Customers 162,397 192,171 Hospital 104,452 107,892 UAF 10,967 50,549 CIRI Talkeetna Lodge 11,998 13,410 Total Sales,Mcfly 719,422 859,536 "thousand cubic feet per day FNG's annual gas sales are currently about 1 Bcf/y.The University of Alaska Fairbanks and Fairbanks Memorial Hospital are their largest customers.The gas distribution network in In-State Gas Pipeline Supply Options Study Page 24 Fairbanks currently comprises approximately 65 miles of buried main lines and 15 miles of buried service lines. 6.1.1 Interior Market Growth and Penetration Most Interior commercial and residential customers use heating oil for space heating and domestic hot water.The current market for natural gas in the FNSB has been limited due to supply constraints.Currently,no large industrial loads are serviced by the existing gas distribution network.The largest loads currently serviced by Fairbanks Natural Gas are small-to- large commercial customers.If natural gas were to become available in sufficient quantities,the penetration of the gas market could increase significantly. Potential Fairbanks-area industrial demands include power generation at Golden Valley Electric Association (GVEA)and refining demand for crude conversion at Flint Hills Refinery (FHR)and Petro Star Inc.(PSI). e The GVEA combustion turbines at North Pole are the most likely to convert to natural gas. This would include the new 60 MW combined cycle power plant at the North Pole Expansion (NPE)plant that currently uses liquid naphtha as a fuel source.The expected gas demand for NPE would be approximately 3.5 Bcf/y for the existing LM6000 combustion turbine and up to seven Bcf/y with the installation of an addition LM6000. e The Flint Hills Refinery uses part of the crude stream to fire boilers and its distillation tower for the production of liquid fuels.The burners could be converted to use natural gas as a fuel for refining crude.The expected demand would be approximately 4.5 Bcffy. e Petro Stars North Pole refinery uses both crude oil and non-condensable gases to fuel its crude oil refining process.If the facility replaced crude oil components of its fuel stream with natural gas,maintaining current plant operations and level of output would consume approximately 0.33 Bcf/y of gas. It is important to mention that there is potential for significant new industrial projects that would affect Interior natural gas demand.One project currently under consideration is Coal-to-Liquids (CTL)project.The project is in the preliminary engineering phase and it is yet to be determined if natural gas and coal will be selected as co-feed stock.If gas is selected as a co-feed,the Coal/Gas-to-Liquids (C/GTL)process would initially use up to 93 Bcf/year of natural gas.The earliest the C/GTL project could be online is 2014. A change in the gas supply environment,such as a gas pipeline or a secured supply of North Slope gas,could significantly affect the demand for natural gas.Table 6-3 details the potential growth in gas demand in the Fairbanks area.Growth in the industrial sector would greatly increase demand.The higher demand in the residential and commercial areas can be attributed to the expansion of the FNG distribution network.An assumed population growth is also factored into the projected demand schedule. In-State Gas Pipeline Supply Options Study Page 25 Table 6-2:Fairbanks Estimated Gas Demand 2008 2016 Volume Sold Mcf Mcf GVEA 0 3,219,500 Flint Hills 0 4,878,000 Petro Star 0 329,500 Residential 63,500 173,200 Small Commercial 432,000 1,153,000 Large Commercial 192,200 506,700 Hospital 107,900 107,900 UAF 50,600 200,000 CIRI Talkeetna Lodge 13,400 13,000 Total Volume Sold 859,600 10,580,800 The existing coal-fired power plants on Eielson Air Force Base,Fort Wainwright,and the Aurora Energy plant are less likely to convert from coal to natural gas.However,they have been considered future potential loads in the industrial demand section.Table 6-3 details 19.3 Beffy of additional potential industrial demand if all of the coal-fired generation in the Interior and one of the older GVEA oil-fired North Pole units convert to natural gas.Conversion of these units would be a management decision by the owners of the assets based on factors such as fuel savings,conversion costs,current fuel contract requirements,and environmental permitting requirements. Table 6-3:Future Potential Interior Alaska Industrial Gas Demand Energy Unit Load (Mcf}Count Source Consumption Comsumption Btus/Unit Eielson AFB 1 Coal 183,000 Tons 6900 North Pole 1 DieseV/Oil 28 000,000 Gallons 141,000 Ft Wainwright 1 Coal 195,000 Tons 6,900 Fairbanks 1 Coal 130,000 Tons 6,906 College/UAF 1 Coal/Oil 60,000 Tons 6900 Clear AFS 1 Coal 61,770 Tons 6 900 Healy,GVEA 1 Coal 170,000 Tons 6 906 Healy,Clean Coal 1 Coal 195000 Tons 6 300 Total Unit Measure Lbs/Ton Btus Mcf lbs 2,240 2 828 448 000 000 2,828 448 Gallon 3,948 000 000 000 3,948 000lbs2,240 3 013,920 000 000 3,013,920lbs224020092800000002,009 280 lbs 2,240 927 360 000 000 927 360 lbs 2,240 954 717 120,000 954717 Ibs 2,240 2,627 520,000 000 2 627 520 Ibs 2240 3,013,920 000 000 3,013 920 19,323,165,120,000 19,323,165 The future gas demands listed in the previous two tables are based on information from various reports and studies.The future gas demands assume that gas delivered to the Interior will be competitive enough to encourage switching from existing fuel sources. 6.2 Southcentral Gas Market Nearly 60 percent of Alaskans live in the Southcentral region and have relied on relatively inexpensive gas from the Cook Inlet gas fields.That gas heats homes and businesses, generates electricity,and fuels large industrial loads.The regional population has almost tripled since 1970.Communities along the Railbelt north to Fairbanks have also relied on some of its electricity generated by Cook Inlet gas. In-State Gas Pipeline Supply Options Study Page 26 Table 6-4:Southcentral Gas Market (2001 -2006) Use/User Average (Bcffy) Gas Utilities (ENSTAR)34 Power Generation 38 LNG 73 Agrium Ammonia 40 Field Operations and Other 20 Average Yearly Consumption 205 Historically,the largest users of gas in Southcentral have been LNG export and the fertilizer production from the Agrium Plant.In 2005,the export of LNG and the Agrium fertilizer plant accounted for 37 percent and 19 percent of the Cook Inlet gas demand respectively.Generation of electricity by the electric utilities accounted for 20 percent,while the heating of homes and businesses accounted for 16 percent of the Southcentral gas demand.The remaining 8 percent was used for oil and gas field operations and other uses.; Price-competitive gas and supply issues have forced the closure of the Agrium plant.The LNG export license is only valid through the first quarter of 2011.In spite of reduced industrial demand,diminishing gas reserves in the Cook Inlet fields have dramatically changed the supply landscape for natural gas.Discontinuation of Agrium's fertilizer production has changed the gas use percentage profile,as illustrated in Figure 6-1,increasing gas availability for other uses and users. Figure 6-1:Southcentral Natural Gas Usage by Percentage Ficld Operations &Power Gencration Other Uses (ML&P and 12.1%Chugach Electric) atSOEeee oe 23% 'Gas Utility ({ENSTAR) 20.6% *Data from Department of Energy (DOE)Southcentral Alaska Energy Forum Presentation, September 2008 -Recalcuiated fo reflect Agrium shutdown. In-State Gas Pipeline Supply Options Study Page 27 Figure 6-2,from the Department of Energy's 2004 Southcentral Alaska Natural Gas Study (reiterated in the 2006 Southcentral Energy Forum's final report)illustrates State and Federal projections of sharp declines in gas demand due tothe closing of the Agrium plant and the possible closure of the LNG facility in 2011.However,the past and potential future industrial plant shutdowns appear to only delay the inevitable.As Figure 6-2 also details,decrease in industrial demand alone will not alleviate the supply issue facing Southcentral.If Department of Energy/Alaska Division of Oil and Gas projections prove accurate,non-industrial gas demand could become greater than production from the known gas reserves as early as 2011-with production becoming insufficient to meet total electrical utility demand by 2012 or total space heating demand by 2015. Figure 6-2:Projected Supply of and Demand for Cook Inlet Gas 250 -Base Case All Supply Aggregated -NY200="e -<--_Supply -All Fields Supply fom All FieldsExceptKenai,McArthur River,North Cook Inlet sa Urea Demand LNG Demand Power Generation Demand Gas Utility Demand 2000 2005 2010 2015 2020 2025 Source:NETL/DOE Southcentral Alaska Natural Gas Study (2004) A reduction in gas supply to the Southcentral area's electrical utilities reduces the amount of electrical production that may be transmitted to the Interior on the transmission line between Fairbanks and Anchorage.In past years,GVEA purchased up to 50 percent of its annual power needs from Anchorage area utilities as low cost gas-fired "economy energy”via the Intertie. However,during the past two years,GVEA's economy energy purchases have declined as Cook Inlet gas reserves have declined.According to a recent Cost of Energy filing tothe RCA (Table 6-6),GVEA now only receives about a third of its requirement from gas-fired generation. Therefore,Interior residents are not immune to the effects of declining Cook Inlet reserves, experiencing it in the form of higher electric bills. In-State Gas Pipeline Supply Options Study :Page 28 Table 6-5:GVEA Power Production Data (Aug.2007 through July 2008) GVEA Energy Total Power Cost Avg.MW Avg.|%ofSupplyMWH$Year Per Hour Cost |Mix$/(KWH Oil-Fired 529,988 $63,746,088 60 $0.120 35% Coal-Fired 412,555 $15,753,687 47 $0.038 27% ANC--Gas §19,217 $34,455,270 59 $0.066 34% Hydro 71,298 $3,208,431 8 $0.045 5% Total GVEA 1,533,060 $117,163,476 175 $0.076 Figure 6-3 illustrates fluctuations in seasonal gas demand in the Anchorage area.As one would expect,demand is highest in winter,when the need for heat and light is greatest.With gas reserves depleting and production declining,spikes in residential and commercial consumption on the coldest of winter days (peak demand days)have occasionally outstripped the Southcentral gas system's capacity to deliver.In the absence of increased Cook Inlet production,or the implementation of some mitigation strategy,it is anticipated that Southcentral's gas deliverability problems will worsen in time,with the number of days of peak demand shortfalls becoming more frequent. Figure 6-3:Seasonal Residential and Commercial Demand for Cook Inlet Gas (1999-2002) _(in Heating Degree Days &Mefrd) :ioe Arvechorage HOD we :80 +oe RAC Consumption (Mcfid) 150.000 =* 100,000 20 .50,000 ry I '4 $8 §8 8 g g i =3 4%§§o3 e §§ES §=3 3 § Source:Alaska Division of Oil and Gas 6.3 Total Interior and Southcentral Gas Market The collective gas demand of the Interior and Southcentral markets makes up the majority of gas demand in the State and will continue to do so into the foreseeable future.Between 2010 and 2025,it is expected that in-state average daily use of natural gas will grow from roughly 0.20 Bcf/d at present to as high as 0.70 Bcf/d (provided that Agrium,LNG at Nikiski,and the Fairbanks C/GTL projects remain or come online). In-State Gas Pipeline Supply Options Study Page 29 New in-state,value added,industrial uses and potential LNG and/or propane for Southeast and rural Alaska also are possible future uses of in-state natural gas.The table below shows the expected gas demand for both the Interior and Southcentral markets if all of the potential users convert to natural gas. Figure 6-4:Railbelt Natural Gas Demand Ui Fieki Ops |[we incustrial (5-year Avg.) @ Independent/Direct ||mFNGBENSTAR DHEA .Nikishi Cagen BGOVEA mCVEA m CEAMEAHEASES MAMLAP wWAPC .Tok 2005 2010 2015 2020 2025 Year 6.4 Gas Market Conclusion There is a viable market for natural gas in the Interior,provided that gas is priced competitively enough to encourage residential,commercial,and industrial users to switch from current energy sources to natural gas.Any market expansion of natural gas will require expansion of existing infrastructure.Industry and government should place a high priority on this infrastructure expansion. Assuming no new natural gas is found in Cook Inlet,the demand for gas in Southcentral will continue to outpace gas production.Many geologists think the Cook Inlet basin is under- explored compared to other gas regions,but no one is certain how much gas is left in the basin. Until new Cook Inlet gas is discovered in marketable quantities,alternatives such as a gas pipeline from the North Slope or importing LNG to meet the Southcentral gas future demand must be considered. 7.Gas Pipelines and Supply In recent years,concern has grown about the declining gas reserves in Cook Inlet.Cook Inlet gas provides almost all of the energy needed for heating and electricity in Southcentral Alaska. It also has provided a limited supply of energy to Fairbanks in the forms of LNG and gas- produced electric power.Most of the remaining proven Cook Inlet gas reserves may be depleted within the next 10 years. This past year,the State and private companies have put considerable effort into developing plans for building pipelines or LNG supply systems that could supply natural gas to Fairbanks and Southcentral Alaska within eight years.The following in-state delivery options could be beneficial in delivering natural gas to Interior Alaska: In-State Gas Pipeline Supply Options Study Page 30 e Alaska Natural Gas Development Authority (ANGDA)Spur Line project Build 24”gas line from South Central to Delta with an 8”gas line from Delta to Fairbanks e ENSTAR Bullet Line project Build 24°gas line from North Slope to Southcentral Alaska e Fairbanks Natural Gas (FNG)deliver LNG from the North Slope to Fairbanks Construct LNG plant on the North Slope and truck LNG to Fairbanks A number of in-state gas supply options are also discussed in this Study,including: e North Slope gas basins e Cook Inlet gas basins e Gubik Gas Basin (Foothills of Brooks Ranges,North Slope) e Nenana Basin , e Yukon Flats Basin e Copper River Basin 7.1 In-State Delivery Options 7.1.1 Alaskan Highway Line (TCAlaska or Denali) In October 2004,the Federal government passed legislation providing up to $18 billion in loan guarantees for an Alaska natural gas pipeline project.Since then,the Federal government has encouraged Alaska to finalize a pipeline project that would deliver North Slope gas to the Lower 48. In late 2005,the Administration of the State of Alaska and those who own leaseholder rights to most of Alaska's North Slope natural gas (ConocoPhillips,BP,and Exxon;or,collectively,the Producers)negotiated the terms of a natural gas pipeline contract under the Stranded Gas Development Act (SGDA).The goal of the negotiations was to build a large-diameter natural gas pipeline from Prudhoe Bay to the Midwest.However,the State and Producers did not reach a final agreement before the change of administration.The new Governor opted to pursue further gas pipeline efforts under a new statutory framework,the Alaska Gasline Inducement Act. The State of Alaska passed the Alaska Gasline Inducement Act (AGIA)in May 2007.Like the SGDA before it,AGIA's purpose was to expedite the construction of an Alaska Highway pipeline that would transport Alaska gas to market.After a competitive application process,and thorough public and legislative review,in 2008 the State awarded TransCanada its exclusive AGIA license. Also in 2008,two of the North Slope producers,BP and ConocoPhillips,announced they had formed "Denali The Alaska Gas Pipeline LLC,”which is in competition with TransCanada to build and operate the Alaska Highway pipeline.They have pre-filed with the Federal Energy Regulatory Commission (FERC)to begin permitting and licensing the 48-inch gas pipeline. Though it is likely FERC will only be issuing one pipeline license,proponents of both TCAlaska and Denali pipelines appear to be moving forward with their projects. In-State Gas Pipeline Supply Options Study Page 31 Figure 7-1:Alaskan Highway Line:North Slope to Alberta é Fat Nelson bh Pg BO Doge.BS yparoF,.as ha ike ale,Government of Yukon,Yukon Territory,Canada Preliminary designs indicate the large-diameter natural gas pipeline will follow the route of the existing Trans-Alaska Pipeline System (TAPS),passing near Fairbanks on its way to Delta Junction (Figure 7-1),before departing the State of Alaska proximate to the Alaska/Canadian Highway.Both TCAlaska and Denali are planning a line that will be approximately 48-inch diameter steel pipe,with an anticipated operating pressure of about 2,500 psi (pounds per square inch).Subject to agreements,initial average capacities for the lines are expected to be between 4.0 and 4.5 Bcffd at startup,expandable up to 5.9 Bcf/d with the addition of compressor stations.At 1,715 miles from Prudhoe Bay to the expected connection point in Alberta,the TCAlaska project is currently estimated to cost $25.1 billion,and the Denali project $30 billion. Table 7-1 lists information from TCAlaska and Denali that briefly describes their respective projects in physical and economic terms. In-State Gas Pipeline Supply Options Study Page 32 Table 7-1:North Slope Gas Pipeline Projects Denali Pipeline Start Prudhoe Bay Pipeline Terminus Alberta Total Length -miles 1,730 Pipe Diameter 48" Designed Pressure 2,500 PSI Compressor Stations: -In Alaska -In Canada Pipeline Capacity Estimated Cost 8 to 12 4.0 Befid $30 billion TCAlaska Prudhoe Bay Alberta 1,715 48" 2,500 PSI 6 10 4.5 Befl/d $25.1 billion TransCanada and Denali anticipate holding an open season to acquire gas shipping commitments by the close of 2010.With a successful open season,both companies expect it will take about eight years to design,build,and bring the pipeline into service.The major tasks will include nine months to obtain rights-of-way,four years to complete detailed engineering and field work,and three years to complete construction of the pipeline.While there are some differences in the two projects,under the best-case scenario,gas could flow from the North Slope as early as 2018. Is 2018 Realistic? Recent developments in the Lower 48 natural gas market-specifically,increased availability of gas from unconventional sources-have the potential to negatively impact this timeline. Figure 7-2:Gas Pipeline Tariff Estimates ($/Mcf) 68 ,,0%Growth ' 624-9 Year Trend 9%Growth (1998-2006)(14 2007-1Q 2008} : :>a 2 z i 3 f 2 i |=a t6 |<i2 |a |*Gulf of Mexico Hurricanesi:Katrina 'ara46:Rita =||o || dan-33 Jan-99 Jan-O0 Jan-O1 Jan-62 Jan-O3 Jen-04 Jan05 JanOé6 JanO7 Jan-OS Source:Energy information Administration,Office of Oil and Gas,Form EIA-014 Monthly Natural Ges Production Report In-State Gas Pipeline Supply Options Study Page 33 Advances in technology,coupled with improved geological knowledge and higher commodity prices have,in recent years,resulted in increased domestic production of natural gas from unconventional sources.The U.S.,after nine years of relatively flat natural gas production growth (1998-2007),has started an upward trend that generated 3 percent growth between first- quarter 2006 and first-quarter 2007,followed by an exceptionally large 9 percent increase between first-quarter 2007 and first-quarter 2008 (Figure 7-2).Much of this growth was fueled by increased production from shale,tight gas,and coal bed methane basins. Figure 7-3:Major U.S.Shale Basins Major U.S.shale basing EEE 97" Niobrara Gammon Bakken --Excello/Mulky New Aiban 225-248 tcf Floyd andConasauga Q7tcf Pale Dure \)Barmett and ; " Woodford Barnett Woodford Fayetteville ict =trillion cubic teat 25-252 tcf Source.Schtumberger,Shais Gas,October 2005 According to the Energy Information Administration (EIA),"more than half of the increase in natural gas production between the first quarter of 2007 and the first quarter of 2008 came from Texas,where supplies grew by an exceptionally high 15 percent”over that timeframe.Driving this rapid growth in production has been development of the Barnett Shale formation,located in the Fort Worth vicinity.The illustration in Figure 7-3 details that this basin alone holds an estimated 25 to 252 Tcf (trillion cubic feet)of recoverable natural gas-nearly five times the 55 Tcf of technically recoverable shale gas the EIA conservatively estimated for the entire continental U.S.in 2000 and more than double the EIA's 2007 continental U.S.estimate of 97 Tcf. In-State Gas Pipeline Supply Options Study Page 34 As illustrated in Figure 7-4,provided by Figure 7-4:Gas Supply/Demand ExxonMobil,the rapid development of Balance in N.America unconventional gas has allowed the U.S.in recent years to reverse its aggregate BCFO domestic production declines.It is anticipated 120 «average GrowiYear 2005 -2030 1.0% that continued increases in production from unconventional domestic gas sources, coupled with increases in America's LNG 100 receiving capacity,will allow the Lower 48 to meet its increasing natural gas needs through2030.£0 If the continental U.S.has an adequate supply of natural gas or maybe even over-60 supply,the question must be asked:Would a North Slope gas owner be willing to sell gas UONSNPOle[EDO]eeinto a saturated market and at the same time 40 commit to pay the pipeline owner a guaranteed and unknown transportation fee on an expensive pipeline project?20 Conventional TCAlaska and Denali will both need g tee _.. commitments from gas owners to ship before 2015 20a:construction starts.2000 2015 2039 Large gas reserves in the continental U.S.would normally mean low prices for gas.High construction costs would mean high gas transportation tariffs.A commitment to ship large volumes of gas into a market that has already achieved gas balance in the absenceofthatincreasedsupplycouldleavethegasownerslittleornoreturnontheirgassales.If both TCAlaska and Denali go to open season in 2010,the results of that open season should be telling.Alaskans have significant concerns about TCAlaska's and Denali's projected 2018 project completion estimates. 7.1.2 ANGDA Spur Line The Alaska Natural Gas Development Authority (ANGDA)is a public corporation that was created by Alaska voters through the initiative process in 2002.The language of the voter initiative was as follows: "This bill would create the Alaska Natural Gas Development Authority as a public corporation of the State.The Authority would acquire and condition North Slope natural gas,and construct a pipeline to transport the gas.The Authority's powers would include buying property or taking it by eminent domain,and to issue state tax-exempt revenue bonds.The gas line route would be from Prudhoe Bay to tidewater on Prince William Sound and the spur line from Glennallen to the Southcentral gas distribution grid.The Authority would operate and maintain the gas pipeline,ship the gas,and market the gas.” In-State Gas Pipeline Supply Options Study Page 35 ANGDA,as initially conceived,was formed to facilitate the planning,design,and construction of a large diameter natural gas mainline to bring North Slope gas to Prince William Sound for an LNG facility,and also a spur line off the mainline to supply North Slope gas to Southcentral. However,ANGDA's interpretation of its mission and the specific scope of its project have evolved over time. By 2004,ANGDA had developed a preliminary design and cost estimate for an All Alaska LNG project that could deliver 2 Bcf/d of gas to an LNG facility near Valdez.ANGDA planned to deliver a feasibility study by the end of 2005,complete the engineering in 2007,and construct the $10 billion project in 2010. In 2005,however,ANGDA expanded its original mission and began investigation of a)propane separation at the Yukon River crossing as a future fuel for Interior and rural communities and b) compressed natural gas from the Valdez plant as fuel for Alaskan coastal communities. By 2006,ANGDA's pipeline plans had again changed.With no fewer than two competing entities pursuing construction of a large diameter pipeline originating on the North Slope (the Alaska Gasline Port Authority and the Producers),and the Administration publicly supporting and actively negotiating agreements with one of those entities,ANGDA shifted its focus to one primarily geared toward ensuring in-state distribution of gas.Thereafter,the presumptive source of natural gas for ANGDA's pipeline would be the large 48-inch Alaskan Highway Line, rather than the North Slope directly,and ANGDA studied two pipeline routes for its TAPS- ANGDA Spur Line:a Glenn Highway route originating in Delta Junction,and a Parks Highway route originating in Fairbanks.The Glenn Highway and Parks Highway routes were each about 350 miles long,and both routes were estimated to cost around $1 billion to build.ANGDA focused its continuing efforts on a Glenn Highway routing of the Spur Line. In its current vision,the ANGDA Spur Line would be a 20-to 24-inch diameter steel pipeline and operate at 2,500 psi.The proposed Spur Line (Figure 7-5)includes a 150-mile pipeline segment from Delta Junction to Glennallen,a 150-mile segment to Palmer,and a 70-mile segment to Beluga (Cook Inlet).In 2006,ANGDA was granted a "conditional right-of-way lease”from the Alaska Department of Natural Resources for the Glennallen-to-Palmer segment of the Spur Line.ANGDA's latest estimate of the Spur Line cost is $1.25 billion,and it believes construction could begin in 2010. In-State Gas Pipeline Supply Options Study Page 36 Figure 7-5:ANGDA Spur Line 9 a itorth Stops+!| : » :Alaska Gas|,ruennverSpurline|: : 1 ans"v.370 miles of 20”pipe "»,,cetasnet$1,256 million cost . 250 mmcfpd throughput ah $2.35 /mmbtu tariff 150 mies Seluga Palmer 180 mites Giennalien wad 8 mics a ,' 5 ¢ AS AS*©Kenai ey Vaca ANGDA Presentation:Senate Resource Committee February 25,2008:Amended In 2008,ANGDA committed $1.2 to $2 million in State funds toward environmental studies of the 370-mile Spur Line.Shaw Alaska is performing wetlands delineation along the right-of-way corridor of the Spur Line from Delta Junction to Beluga.ANGDA recently solicited proposals from qualified firms to assist them in beginning the Environmental Impact Statement (EIS) process. ANGDA believes that the Spur Line project would supply Southcentral Alaska with the lowest- priced in-state gas in the future.It justifies this contention by pointing out that if everything goes as planned,the Spur Line will have the cheapest source of gas (the 48-inch,export-oriented Alaska Highway Line)and will supply the largest possible market with that gas (both in-state and,via the Alaska Gasline Port Authority's proposed Valdez LNG facility,global markets).This will allow the ANGDA Spur Line to benefit from economies of scale unattainable by the other proposals. Table 7-2 provides ANGDA's latest pipeline tariff (cost of service)estimates for transporting gas to the Interior and Southcentral regions from the North Slope via the 48-inch gas pipeline and the Spur Line. In-State Gas Pipeline Supply Options Study Page 37 Table 7-2:Gas Pipeline Tariff Estimates 100 250 500 MMcfiday*MMcfiday MMcfiday Fairbanks -From 48"Pipe $1.25 $1.25 $1.25 Cook Inlet -From 48"Pipe $1.50 $1.50 $1.50 -From Spur Line $5.00 $1.75 $1.00 Total $6.50 $3.25 $2.50 *millions of cubic feet per day In ANGDA's estimation,the total cost of North Slope gas delivered to Southcentral Alaska's existing gas transmission system could be around $6/Mcf at 500 MMcf/d throughput. At the Governor's request,in 2008 ANGDA investigated whether the Spur Line could be modified to supply natural gas to Fairbanks within the next few years to help alleviate the area's high cost of electricity and heating with fuel oil.In October in Fairbanks,ANGDA presented an updated plan to build a Spur Line on an aggressive schedule that would bring Cook Inlet gas to the Interior.The revised Spur Line would continue to be a 20-to 24-inch diameter steel pipeline from Beluga through Glennallen to Delta Junction,but with the addition of an eight-inch diameter high-density plastic pipe extension from Delta Junction to Fairbanks.The 370-mile ANGDA Spur Line between Beluga and Delta Junction would be capable of transporting up to 365 Beffy (1 Bcf/d).The 70-mile eight-inch diameter plastic pipeline from Delta Junction to North Pole could deliver up to 7.3 Bef/y (20 Mcf/d),providing enough gas to operate GVEA's 60 MWC combined cycle power plant at North Pole (3.5 Bcf/y),meet Fairbanks Natural Gas's current residential and commercial customers'gas demand (1 Beffy),and provide a limited supply of gas to the Flint Hills Refinery (2.5 Bef/y). Though the steel pipeline between Beluga and Delta Junction would be designed for a 40-year economic life,the eight-inch plastic line to North Pole would last only six to eight years.In ANGDA''s estimation,this six-to-eight year economic life is sufficient as it expects Fairbanks will be able to tap onto the Alaska Highway Line for North Slope gas by then.ANGDA believes that building the Spur Line early could provide the Southcentral gas system with needed peak storage,as the 300-mile Spur Line could act as a storage pipe and deliver gas back into the system to meet daily peak gas demands.ANGDA also believes the small plastic pipe could provide a quick and affordable gas connection to the Fairbanks area. 7.1.3 ENSTAR Bullet Line ENSTAR has been a natural gas utility in the Anchorage area since 1961.Today it has 3,100 miles of gas transmission pipelines and distribution mains serving more than 128,000 customers in Southcentral Alaska.ENSTAR currently has three long-term contracts and two short-term contracts with Cook Inlet producers,and will be going into the marketplace with a request for proposals in early 2009 for gas supplies for 2010/2011.Despite these efforts,ENSTAR believes it could have unmet requirements of 10 Bef4y by 2015.ENSTAR has also had difficulty obtaining sufficient gas to meet its customer demand during winter peak periods and plans to develop underground and peaking storage to avoid shortages on peak winter days. In-State Gas Pipeline Supply Options Study Page 38 Figure 7-6:ENSTAR Bullet Line ma Prudhoe Bay anen ENSTAR Pipeline Alignment (Proposed)|: o»Fairbanks Lateral a=Prudhos Akernate |wen Gubik Alternate « KHSTAR Transmission System 4 mw Roads: us 5 Beluga Pipeline GaP 39 Facility} ea ENSTAR Presentation:Alliance,Fairbanks Chapler December3,2008 In 2007,ENSTAR contracted with Arctic Slope Regional Corporation and Michael Baker Engineering to study building a pipeline that could deliver North Slope gas to the Anchorage area.The proposed route would follow the Parks and Dalton highways,as illustrated in Figure 7-6.The 690-mile pipeline,now referred to as the ENSTAR Bullet Line,would bring dry natural gas from the Gubik gas field (located on the northern foothills of the Brooks Range)to the Interior and Southcentral regions.The pipeline would be 20-to-24 inches in diameter,operate at 2,500 psi,and have an initial capacity of up to 0.5 Bcf/d.The pipeline's maximum design capacity would be 1.0 Bcffd.ENSTAR plans to provide a lateral line to Fairbanks that will tap off the main Bullet Line near Dunbar.The Fairbanks lateral line could deliver about 30 Bcffy to the Fairbanks market. In 2008,ENSTAR spent $5 million for preliminary engineering and permitting of the Bullet Line and has budgeted $15 million for 2009 to continue that process.Two companies (HC Price and Michael Baker)are preparing cost estimates for building the pipeline,which should be available by March 2009.ENSTAR's current cost estimate for building the Bullet Line is $3.8 billion. The Gubik field (more fully described in subsection 7.2.3)currently has 600 Bef of estimated natural gas resources.However,ENSTAR's Bullet Line will need at least 3 Tcf of proven gas reserves to sustain its operation of 150 Bcffy for the next 20 years.If Anadarko's exploratory drilling program fails to prove sufficient reserves in the Gubik area to meet this threshold,or fails to prove those reserves in a timely enough manner,it may be necessary for ENSTAR to extend the Bullet Line to obtain North Slope gas:gas that is "wet”and will require a gas conditioning plant to remove COz,moisture,and gas liquids from the production stream before it enters the ENSTAR pipeline.A conditioning plant for a Denali or TransCanada pipeline is estimated to cost In-State Gas Pipeline Supply Options Study Page 39 $5 to $6 billion.The gas conditioning plant for a smaller ENSTAR Bullet Line would be less expensive but still a significant additional project cost. ENSTAR believes it can build the Bullet Line in five to six years and have it ready for service by 2015.Its goal is to have the pipeline in service just as its contracted gas from Cook Inlet producers drops off.The initial pipeline field engineering work is expected to be complete by spring of 2009,and management could decide to move forward by June 2009.ENSTAR states it would then commit $60 million toward building the pipeline by completing its design and obtaining needed permits. ENSTAR has invited three Alaska Native corporations to invest in the project.According to ENSTAR,the Bullet Line project has a corporate commitment of up to $1 billion,and a final decision on building it could occur in 2010.It could be built by ENSTAR's subsidiary company, Alaska Pipeline Company,and construction could be complete before major construction begins on the 48-inch Alaska Highway gas pipeline to the Lower 48. According to ENSTAR,gas would be procured by ENSTAR,GVEA,Flint Hills,FNG,etc. (referred to here as "the Customers').ENSTAR would operate the pipeline and charge a tariff for transporting the purchased gas through the Bullet Line from the gas field to the Customers. ENSTAR charges $1.70/Mcf to deliver gas to its residential and commercial customers in Southcentral,for a total delivered cost of $10.76/Mcf.The $10.76/Mcf charge includes the cost of Cook Inlet gas,along with its transmission and metered delivery to consumers.According to ENSTAR's initial estimates,the cost of gas delivered through the Bullet Line to Southcentral will be $10/Mcf to $12/Mcf.Also,ENSTAR expects gas to the Interior could be slightly cheaper because of a lower Bullet Line tariff,which it estimates at $2.50/Mcf based on a gas flow rate of 0.5 Bef/d. ENSTAR says its proposed Bullet Line has the support of an experienced pipeline company with access to private financing,and that the project could be in service within five to six years. ENSTAR believes the Bullet Line would provide all of the gas needed by Southcentral and Interior Alaska for the foreseeable future. 7.14 Fairbanks Natural Gas (Trucked LNG) Fairbanks Natural Gas (FNG)is a private natural gas utility providing gas service to Fairbanks. It began service in 1998 and currently has about 1,100 residential and commercial customers. The company's gas supply system has grown each year and currently has 65 miles of buried main lines and 15 miles of feeder lines serving University of Alaska Fairbanks,South Fairbanks, Fairbanks Memorial Hospital,Doyon Estates,Bentley properties,and a small area off Trainer Gate (new military housing).FNG estimates the cost to expand the distribution system at $140,000 to $200,000/mile.FNG's current annual gas use is about 1 Bcf and it charges its customers an average of $22.91/Mcf for delivered gas. FNG currently purchases Cook Inlet gas,which is liquefied at a Point McKenzie plant and trucked in specialized tanker trailers to its two LNG storage and re-gasification facilities in Fairbanks.FNG averages about three 800 Mcf truckloads per day with up to eight truckloads daily during peak winter demand.The LNG is stored at FNG facilities in Fairbanks,where it is expanded and fed into the gas distribution system.FNG currently has LNG storage capacity for five to six peak days. In-State Gas Pipeline Supply Options Study Page 40 FNG had contracts for Cook Inlet gas through December 2008,and has secured firm gas contracts to provide service through May 2010.Aurora Power agreed to supply gas to FNG for three months (January through March 2009),and then FNG has a 14-month contract with ConocoPhillips that should guarantee FNG customers a gas supply through May 2010. Because of decreasing reserves in Cook Inlet,FNG's affiliate Polar LNG,LLC,signed a gas supply contract in February 2008 with ExxonMobil for a future supply of North Slope natural gas. This contract would commence upon completion of the Polar LNG facility and provide FNG up to 17 Bcf of gas per year for at least 10 years.In 2007,FNG stated in a news article that its anticipated price for gas on the North Slope would range between $1 and $4 per Mcf- substantially less than what FNG had been paying for Cook Inlet gas purchased from ENSTAR. More recently,FNG said its price for North Slope gas currently ranges between $1.50 and $6/Mcf. Polar LNG plans to install a gas conditioning and liquification facility on the North Slope that would provide future gas for the company's gas distribution system in Fairbanks.The new North Slope facility will be capable of producing up to 50,000 Mcf of LNG per day using five 10,000 Mcf/d compressor trains.The LNG trains would include gas conditioning to primarily remove CO,and moisture.The plant would also separate out propane/ethane (in excess of 30,000 gallons/day for propane)which FNG could sell in the marketplace. The North Slope LNG would be shipped 500 miles via the Dalton Highwayto Fairbanks in new LNG tanker trucks.These truck tankers are larger size (1,000 Mcf capacity),and FNG estimates the transportation cost will be $2,600 to 4,000 per load ($2.60 to $4/Mcf).FNG plans to install additional LNG storage tanks in Fairbanks to maintain the five to six peak days of local storage. FNG estimates that 30 trucks a day could deliver all of the liquefied natural gas necessary to meet the demands of a future Fairbanks gas market of up to 30,000 Mcffd. FNG has spent close to $1 million developing the project,which was originally planned to begin service by mid-2009.FNG has secured property in Deadhorse,has received many of the necessary permits from regulators,and has completed the pre-engineering,site survey,and geotechnical design needed for the construction pad.FNG estimates that its new LNG supply system from the North Slope to Fairbanks would cost,depending on size,between $50 and $250 million.; 7.1.5 in-State Delivery &Supply Comparison Table 7-3 compares the three potential gas transportation and supply options that could deliver gas to Fairbanks in the next eight years. In-State Gas Pipeline Supply Options Study Page 41 Table 7-3:Natural Gas Supply Options to Fairbanks ANGDA ENSTAR FNG Spur Line Bullet Line Trucked LNG Gas Delivery Capacity 0.02 BcfiDay 0.08 Bcf/Day 0.04 BcfiDay 7 BeffYear 30 BeffYear 13 BeffYear Present Gas Cook Inlet =?Cook Inlet =?N.Slope = Reserves -BeffYr Gubik =?10 to 17 Pipeline -Dia.20”-24”to SC 20”to 24”to SC n/a 8”to Fbnks 12”to Fbnks Pipeline Pressure 2,500 2,500 n/a Potential Gas Cook Inlet =7 Cook Inlet =7 N.Slope = Resource -Tcf Glennallen =?Gubik =1 to 3 35 to 80 Nenana =2to 10 YK Flats =5to 15 Cost $1.25 billion $3.8 billion $50-250 million Gas Delivery -Yr 2015 2016 2011 Funding Source Public Private Private Project Headquarters Fairbanks Anchorage Fairbanks Est.Delivered Gas ?$12 Competitive with Fuel Price -$/Mcf Oil 7.2 Gas Basins (Known and Potential Natural Gas Resources) There are six natural gas basins that could potentially supply gas to Fairbanks.Two of them have been producing gas for at least 25 years.The others are under evaluation and/or exploration.This section briefly describes each gas basin. 7.2.1 North Slope Basin Alaska's North Slope began oil production at Prudhoe Bay in 1977,which increased to 2.2 million barrels per day by 1988 and then declined to below 900,000 barrels per day by 2005 *(Figure 7-7).The present recoverable natural gas on the Alaska North Slope is estimated to be about 35 Tcf.The U.S.Department of Energy (DOE)published an assessment and detailed analysis of the oil and gas resources of the North Slope in 2007.They estimate that exploration efforts over the next 20 years could identify an additional 2.9 billion barrels of economically recoverable oil and 12 Tcf of gas.Over the next 50 years,exploration could potentially identify an additional 28 billion barrels of recoverable oil and 35 Tcf of gas.Therefore,the existing 35 Tcf of economically recoverable natural gas reserves on the North Slope could increase to 47 Tcf in 20 years and potentially to 82 Tcf as exploration continues. In-State Gas Pipeline Supply Options Study Page 42 Figure 7-7:North Slope Basin (North Slope Oll and Gas Activity 2008] Heanfert See Bt Fe Raped WES Wess Rance:Oceen Dore Cewe Seine.nce "Ae15 or 2 basi x28 fas 8 EN pe HGa ; ccs National Patroimam.5°!fa os.Reerwe»Ainaha we 3a airae 30a Oring s0er zee:OR Portes «wet,Comer ey Lectaa ong:4 eo.a "i"PeresTestfeeerrtUnind.5Bircane'teases tceck Una 2008 Exploration Activity OL 8 FE eT EES fOK dot@rmemmenemcrneiene con ,woe lta? ES Pe .aN SSRN5ntewnan3icanialreretya. Raw gas from North Slope reservoirs is "wet”and contains 12 percent CO2 gas,moisture,and natural gas liquids (propane,butane,etc.)that will require conditioning before shipment.Gas sold from mature fields on the Alaska North Slope will reduce reservoir pressure and could reduce oil production.The Producers plan to re-inject the separated CO2 gas back into the reservoir to enhance oil recovery. 7.2.2 Cook Inlet Gas Basin The Cook Inlet Basin has been in production since 1958.The area has 28 "dry”gas accumulations and eight oil accumulations (Figure 7-8).Virtually all of the natural gas fields were located by 1970.Its continued development has produced a steady annual output of 200 Bcf/y for the past 20 years.This basin has been the sole supplier of natural gas for all of Southcentral's power generation facilities,and residential,commercial,and major industrial customers (ConocoPhillips LNG,Tesoro Refinery,and Agrium Ammonia plants). In-State Gas Pipeline Supply Options Study Page 43 Figure 7-8:Cook Inlet Basin 2006 -2008 Cook Inlet Oil and Gas Activity fog Lot oe ¢? I .(Reems toesJon toma re xp ,'On AnD AG :Bhar9Ure Cia Us Hernan VeetonFee'acreage foarte Rised Cae ord Lees ft Mag:BorensteinIM catemnsticon 2Seanadmae Farr Samcaaerier Lrt Agr tiemed tes TORI, :ayxanewaden AireReguPats,AG ASED 1.090,909 ZagCe Gis Ao ©DEVELOPMENTWELLSDRELED 7/206-12/007 oft @ CELLS PERMITTED PLANKED 200?1058 5 #GAS INJEZTION SERVICE NEL PereCookinletOilAndGas'Activity Map 2006-2008:AK Division of Oi]&Gas According to a June 2004 report published by the U.S.Department of Energy,the Cook Inlet Basin had produced 6.4 of its known 8.5 Tcf gas reserves.The annual gas production from the basin has started to decline and is expected to drop from 200 Bcf/y to 20 Becff/y by 2025.The |Cook Inlet gas fields are expected to meet commercial and residential consumer demand through 2014,assuming that industrial gas use is curtailed (Figure 7-9) In-State Gas Pipeline Supply Options Study Page 44 Figure 7-9:Base Case All Supply Aggregated Base Case All Supply Aggregated ---_Supply -All Flies ;Supply fom ail Fields"ene Exsept Kenai,MoArthur River,North Gout Intet Urea Demand SRG Demand Ececkd Power Gene-ation DemandBEESasUuiyDemand Gas,Betfyear1=°oJ50 2005 Source:NETL/DOE South Central Alaska Natural Gas Study (2004) 2010 2015 2020 2025 Exploratory drilling during the past five years has only located an additional 200 Bcf of gas, which increases the field's ability to meet demand until 2015.Table 7-4 shows expected shifts in Southcentral gas usage as production from the the Cook Inlet Basin declines over the next 12 years. Table 7-4:Cook Inlet Field Expected Future Gas Supply Average Expected Expected |Expected 2001-2005 2010 2015 2020 (Bcf)(Bcf)(Bcf)(Bcf) Power 37.2 40 0 0 Generation Gas Utility 33.3 35 45 20 LNG 73.6 73.6 0 0 Ammonia-Urea 44.1 0 0 0 Other 15.4 Total -Bcfly 203.5 173.6 45 20 The existing Cook Inlet gas fields can no longer produce sufficient natural gas to meet seasonal winter gas demands.The Kenai LNG facility has been providing peaking gas supplies by reducing its plant input to allow ENSTAR and Chugach Electric to meet their peak gas demands. ENSTAR is having difficulty securing a future long-term supply from Cook Inlet gas producers. The ConocoPhillips LNG export license was to expire in 2009.However,in 2008, ConocoPhillips and Marathon Oil entered into an agreement with the State of Alaska in an effort to extend their U.S.Department of Energy LNG export license to March 31,2011.This agreement requires the gas producers to continue negotiations with ENSTAR and Chugach In-State Gas Pipeline Supply Options Study Page 45 Electric Association on agreements to satisfy local gas supply needs.ConocoPhillips and Marathon also agreed to drill seven new wells in 2008 and share the well data with other potential oil and gas explorers. The 2004 DOE report indicated a small potential that the Cook Inlet Basin contains up to 17 Tcf of gas.The actual recoverable gas depends on access to prospective areas and a large capital outlay.According to DOE,it could require $4 to $6 billion over the next 20 to 25 years to locate and develop the remaining gas.Up to 50 percent of the potential oil and gas fields are located under Federal and State wildlife refuges,parks,and restricted areas.Many of these prime exploration areas have restricted access or are off limits to drilling.In October 2008,the Federal government determined that beluga whales in Cook Inlet are endangered and will require additional protection.This listing could significantly limit future offshore oil and gas drilling of the Cook Inlet Basin. 7.2.3 Gubik Gas Basin The Gubik area is located in the foothills of the Brooks Range near Umiat,which is about 70 miles west of the Dalton Highway (Figure 7-10).The Navy and U.S.Geological Service (USGS) discovered natural gas was there in the early 1950s while exploring the National Petroleum Reserve #4 for oil.They found "dry”gas in shallow wells (1,500 to 6,000 feet deep)and estimated the outline of the Gubik field to be a thin structure about eight miles long and two miles wide.In 1951,the Navy estimated the Gubik field had 600 Bef of gas resources.The Arctic Slope Regional Corporation (ASRC)has both surface and subsurface ownership of the Gubik field area. Figure 7-10:Gubik Basin we "Dosw 5"Arctic Ocean _ 7 .gy en ei om,re ee ee aishrs{oe io a -4eedPYogmansa™ arene 3 Va amyia*;L "8 beg 3Leevebgttatai.Meeutort Sea;esPiisesdisns,a oa omeeetelced a sor eo7to.A miBesaithndnitag;cha Ceeia OW SP RA,7 iePowPaElone:a]¥Lag ooiy|) ee >Bees 3 wom FEB daiwa oj NE NORA ities a c ea - >tee "7]Pomeres Bee -_onan"Lo ee Becaig "OO tee eee a=_Fat . a eT me oe SMapeswaeSOeadaerSO:[ aom"Ot In-State Gas Pipeline Supply Options Study Page 46 Anadarko Petroleum leased the Gubik area through a deal with ASRC and nearby areas through State lease sales.According to its published 2007 Drilling Proposal,Anadarko and its partners,Petro-Canada and BG Alaska,plan to explore the Gubik and Chandler areas based on existing knowledge of the reservoirs and terrain during the winters of 2007-2009.They have identified six potential exploratory well sites.The first well,named Gubik #3,would be drilled to a depth of 4,250 feet.The next well,Chandler #1,would be drilled up to 10,800 feet. In 2007,Anadarko drilled and discovered gas in two zones at its Gubik #3 well.They also made progress drilling the Chandler #1 well located about 12 miles east of Umiat.This winter (2008- 09),Anadarko expects to finish the Chandler #1 well and move to a new well site,Gubik #4. Anadarko acquired a second drill rig and plans to drill another well (Wolf Creek #4)on the west side of the Colville River.The Wolf Creek well expands Anadarko's exploration area into the National Petroleum Reserve-Alaska (NPR-A)on their Federal leases. Anadarko recently said its holdings (Gubik,Chandler,and Umiat)could contain a potential 2 to 10 Tcf of natural gas.Anadarko hopes the exploration wells through 2010 will increase the field's reserves tothe 1 to 3 Tcfrange. 7.24 Nenana Basin The 8,500-square-mile Nenana Basin lies in a long,narrow northeast trending Zone just a few miles northwest of the town of Nenana (Figure 7-11).The basin exhibits similar geology to the Cook Inlet Basin and is considered a good prospect for natural gas.Past exploration of the area has been limited,but focused on oil.Unocal drilled one well near Nenana to a depth of 3,062 feet in 1962,and ARCO drilled a well in the Totek Hills to a depth of 3,590 feet in 1984.Both of these wells lie at the shallow edge of the basin,and drillers did not find commercial quantities of oil or gas.There were "shows”of conventional natural gas in the ARCO well;they also encountered favorable source rocks,which they expect to find in the deeper parts of the basin. In-State Gas Pipeline Supply Options Study Page 47 Figure 7-11:Nenana Basin Exploration Area "Electric :;:Ng interties eeehaaeBEaeSe * *Pad :ore a yy .te In 2003,Denver-based independent Andex Resources purchased and reevaluated the Shell 2- D seismic data gathered in 1982 prior to a State oil and gas lease sale.Andex geologists believe the basin could be as deep as 16,000 feet,which is also a commonly held view in public literature.Their assessment indicated the possibility of mean case of 3 Tcf of technically recoverable conventional natural gas in the basin.By comparison,the Cook Inlet Basin has produced about 6 Tcf of gas over the past 45 years.There has been no assessment of shallow coal bed methane possibilities in the basin. In 2002,Andex applied for a State exploration license,which was approved covering State lands in the 500,000-acre Nenana Basin area.The terms of the seven-year license-recently extended to 10 years-included a work commitment of $2.5 million.In 2004,Andex formed a partnership with Doyon,ASRC,and Usibelli Energy LLC and completed a 2-D survey west of Nenana in 2005.The group also holds exploration rights to Alaska Mental Health Trust (AMHT) and Doyon lands in the basin.A significant portion of the State lands under license have been identified by the University of Alaska to become part of their land entitlement. The Nenana Basin exploration suffered a setback when Andex pulled out of the group because of the Alaska State Legislature's action in 2006 to enact a petroleum profits tax (PPT)of 22.5 percent on petroleum profits.When the Legislature revisited the State oil and gas production tax in November 2007,Doyon and others were able to get the same preferential tax rate for gas from the Nenana Basin as is paid on gas production in Cook Inlet. In November 2008,a revitalized consortium consisting of Doyon Limited,Arctic Slope Regional Corporation,Usibelli Energy,and Babcock &Brown Energy LLC (now Rampart Energy LLC) announced their plans to drill at least one 10,500-foot exploration well four miles west of the In-State Gas Pipeline Supply Options Study Page 48 town of Nenana next summer.This will be the first deep drill test of the basin.If gas reserves prove available,the Nenana Basin lease holders expect to serve several markets,including electric power generation and piped gas to Fairbanks and Anchorage. Crews are expected to haul the Arctic Wolf,a Doyon drilling rig,from the North Slope to Nenana in late March or April,with drilling likely to commence in June 2009.If the early exploratory efforts are successful,the basin could be releasing enough gas to generate power at Nenana within three to five years (2011 to 2013)with gas potentially available for transmission sometime thereafter if additional gas is discovered. 7.2.5 Yukon Flats Basin In the Yukon Flats region of Interior Alaska,recent USGS assessments indicate probable existence of recoverable oil and natural gas resources (Figure 7-12). Figure 7-12:Yukon Flats Oil and Gas Prospects mrt 41k:---A COMUROnfF ats Oil:'And Gas.ProspesteeSMuonNeGAYS.£45 Ga :Primary Oil and Gas Prospects us phe 4 [J Doyon Ownership']--TAPS ;|--Roads }sterieFromUSGS0OFR2006-1204 Tgyg:eet'USGSBIR 2007-5284 ae ey:ty inl,oe In December 2004,the USGS completed and published a resource evaluation of petroleum prospects in the Yukon Basin and concluded that the region had good prospects for gas but limited possibilities for oil.The major data elements of this study included proprietary data shared by Doyon Limited and Exxon (2-D seismic and shallow core drilling)and new data gathered by USGS (airborne magnetic survey).The agency's mean or 50 percent chance estimate included 5.5 Tcf of natural gas,173 million barrels of oil,and 127 million barrels of natural gas liquids in conventional,recoverable accumulations.They believe there is a 5 percent chance that the Flats have 14.6 Tcf or more.The USGS's upper estimate of liquids potential is In-State Gas Pipeline Supply Options Study Page 49 592 million barrels.Doyon agrees generally with the gas assessment,but is more optimistic about oil,estimating oil possibilities in excess of 1 billion barrels recoverable in its mean case. USGS has published additional technical studies on the basin over the past several years.Now identified are several deep sub-basins ranging from 9,000 feet to 16,000 feet,in addition tothe well-known deep center of the basin which could be up to 27,000 feet deep.A USGS study from earlier this year now predicts that oil and gas should be encountered at significantly shallower depths.If correct,this should substantially increase hydrocarbon possibilities because more potential source rocks will be subject to temperatures that could convert organic materials to oil and gas.One of the interesting new prospects is near Stevens Village on the Yukon River, which is relatively close to the Trans-Alaska Pipeline (about 35 miles)and about 150 miles to Fairbanks. The Flats lie entirely within the 11 million-acre Yukon Flats National Wildlife Refuge,which is managed by the U.S.Fish and Wildlife Service.Doyon owns the rights to minerals on more than 2 million acres of land within the refuge and has a land exchange pending in the Yukon Flats with the U.S.Fish and Wildlife Service that would allow the corporation to acquire Federal government-owned land adjacent to its own lands.This land exchange would make exploration and future development more efficient,and achieve certain habitat protection goals.About 110,000 acres of refuge lands to be exchanged are located over the deepest part of the Yukon Flats basin.If exploration moves ahead,additional 2-D seismic exploration would be necessary in the prospective areas before drilling.Doyon is now considering leasing oil and gas rights to exploration groups before any resolution of the pending land exchange.If exploration begins within the next year or two and meets with early success and aggressive development especially in the Stevens Village area,then substantial amounts of gas could be available sometime between 2015 and 2020. 7.2.6 Copper River Basin There may be oil and gas in this geologic basin near Glennallen.By 1983,there were 11 exploration wells drilled in the undeveloped Copper River Basin.Forest Oil and others obtained an exploration license from the State and recently drilled on land owned by Native regional corporation Ahtna,Inc.They hope to find up to 100 Bcf or more of gas that could justify building a pipeline to develop a local gas market and sell gas to Copper Valley Electric Association. Right now it appears unlikely that gas from the Copper River Basin will ever reach the Fairbanks market. 7.3 Gas Basin Summary Currently,the North Slope gas fields have the largest known reserves,followed by Cook Inlet and Gubik.Table 7-5 compares the six gas fields that could supply gas to an in-state gas distribution system. In-State Gas Pipeline Supply Options Study Page 60 Table 7-5:Comparison of Natural Gas Basins Cook Nenana Inlet Basin |Yukon Flats Gubik |North Slope Gas Quality Dry ??Dry Wet Gas Field Potential 8 Tcf 1 to 6 Tef 5to 15 Tcf |2 to 10 Tef 47 to 82 Tcf Known Reserves 1.5 Tcf ??600 Bcf 35+Tcf Gas Available Now |2012 to 2015 ?2016 Now Field Use Current Gas Flow |200 BcffYr 0 "0 0 8-9 Befid 8.Conclusions In 2007,FEDC published a report by the Interior Issues Council:Cost of Energy Group on the high cost of energy in Interior Alaska.That report,titled Fairbanks Energy Plan,stated in part that "Fairbanks has relied heavily on petroleum as an energy source for electricity,space heating,and transportation.The economyof Alaska is being crushed by the increasing cost of crude oil ...” Now,18 months after that report's publication,the cost of energy in the Interior has decreased by 25 percent,but the total energy costs in the Fairbanks North Star Borough are still a staggering $450 million per year.Even with reduced oil costs and increases in the cost of Cook Inlet gas,Fairbanks area residents continue to pay almost twice as much per capita for space heating and electricity as the average Anchorage resident-but disturbingly,about half that of many rural residents. The goal of the Fairbanks Energy Plan was to identify a way to break the grip volatile crude oil prices have had on Interior and Rural Alaska.An additional goal was to find solutions to our growing PM 2.5 non-attainment problem.These objectives are the underlying considerations for the following conclusions. According to information in the 2007 Fairbanks Energy Plan,nearly 50 million gallons of fuel oil are consumed annually in the Fairbanks area for residential and commercial space heating;anamountoffueloilroughlyequivalentto6.2 Bcf/y of natural gas.However,as discussed earlier, there are only about 1,100 natural gas customers in the Fairbanks area,with a combined annual gas consumption of less than1 Bcf/y.Therefore,Fairbanks has an existing potential gas market of up to 6.2 Bcffy,in addition to its industrial growth potential. Maximizing Fairbanks'gas market potential will require an expansion of the existing gas distribution system.The existing distribution system has 65 miles of gas pipe and only penetrates 15 percent of the Fairbanks market.Each additional mile of distribution system is estimated to cost $150,000 to $200,000 to install.Therefore,expanding Fairbanks'gas infrastructure to accommodate 70 percent market penetration could cost more than $50 million. Such a build-out of the Fairbanks market,along with any other in-state markets where large- scale gas delivery may be feasible,is critical because any bullet line Alaska chooses to pursue will require finding additional gas consumers.As a rule,lower gas volumes result in higher pipeline tariffs and a bullet line will need an expansion of residential/commercial/utility demand as well as new industrial customers to increase its gas flow to 0.5 Bcf/d to be economically In-State Gas Pipeline Supply Options Study Page 51 viable and deliver affordable gas.Some potential users could be the existing electrical utilities, the LNG market,refineries (Flint Hills,PetroStar,and Tesoro),and possibly Agrium.Other possible future industrial customers could be future large-scale mining operations or the proposed Coal/Gas-to-Liquids plant near Fairbanks. This current Report evaluates three options that may enable the Interior to begin switching its current fuel oil heating demand to clean and cost effective natural gas within the next 10 years. 8.1 Fairbanks Natural Gas LNG Option Fairbanks Natural Gas (FNG)has provided Fairbanks with a reliable source of natural gas for the past 10 years and currently provides gas to 1,100 customers in a limited area around Fairbanks.Its annual gas sales are less than 1 Bcf by volume,which represents about 15 percent of the FNSB's space heating market. FNG's gas supply contracts with ENSTAR and Cook Inlet producers will expire in May 2010.FNG has secured a 10-year gas supply contract with ExxonMobil for North Slope gas and is studying the possibility of building a 50,000 Mcffd LNG/gas conditioning plant on the North Slope and acquiring a fleet of natural gas tanker trucks to deliver that gas to the Fairbanks market. FNG is the Interior's only source of gas,and its gas contracts from the Cook Inlet are questionable beyond 2010.Providing gas for Fairbanks'current 1,100 customers beyond 2010 is essential and the Fairbanks Natural Gas LNG proposal can satisfy this requirement. However,for natural gas to solve the Fairbanks PM 2.5 issue,the FNG gas distribution system would require significant expansion from 1 Bcffy to 13 BcfAy and reach as many as 10,000 customers.The Task Force believes that because of the apparent high cost of the FNG project, it is unlikely that without government support,FNG's plan will be able to deliver gas to the Fairbanks market at a price that would encourage market penetration.Without significant market penetration,this plan would neither reduce area-wide particulate emissions nor the community's cost of energy. Conclusion In the Task Force's assessment,FNG's trucked North Slope LNG proposal is the fastest option for delivering gas to Fairbanks,and the only option that allows FNG to maintain its current customer base and continue to supply a cleaner burning fuel to an area already experiencing a PM 2.5 attainment problem.However,without some level of government support,the Task Force believes that the FNG plan would only be a solution for supplying gas to 1,100 customers; it would not reduce aggregate community energy costs or improve air quality within the next five to six years. 8.2 ANGDA Spur Line The ANGDA Spur Line faces a major challenge in obtaining a timely gas supply for the Southcentral gas market.The Anchorage area has recently experienced gas shortages during peak demand periods.Several recent studies confirm there could be critical gas shortages in Southcentral as early as 2015.New gas discoveries in Cook Inlet could partially alleviate this problem,but have not kept pace with the demands of the Anchorage bowl,and continuing gas exploration in Cook Inlet faces significant challenges. In-State Gas Pipeline Supply Options Study Page 52 The ANGDA Spur Line will need to deliver gas to Southcentral Alaska by 2015 to alleviate shortages.The earliest the 48-inch Alaska Highway Gas Pipeline could be completed is 2018:a completion date the Task Force questions.ANGDA believes there are potential gas resources around Glennallen,but it makes little sense to build a gas line on mere hopes that future gas might be discovered to fill it.New large discoveries of natural gas in the Cook Inlet or the Glennallen area must be developed before an eight-inch pipeline extension on the ANGDA Spur Line could benefit Interior Alaska. If ANGDA were to complete construction of its proposed Spur Line in 2014,there most likely will not be gas available for the Interior market.Therefore,without sufficient Cook Inlet gas available to ship north and no North Slope gas available to ship south,the only value the Spur Line could provide is as gas storage for meeting peak demand periods in the Southcentral region.The Task Force believes other less expensive and more timely storage options could be implemented to address Southcentral's daily peak gas shortages. Considering that the ANGDA project is estimated to cost $1.25 billion and offers few to no discernable benefits to the residents of Interior or Southcentral Alaska,its cost-to-benefit ratio is unacceptable. Conclusion The ANGDA Spur Line is fatally flawed.It cannot deliver gas to the Interior that is simply unavailable from Cook Inlet.The Spur Line cannot supply North Slope gas to Southcentral until at least 2018,which would be a minimum of three years too late to meet Southcentral demands. The ANGDA Spur Line would not deliver timely or adequate gas to Interior or Southcentral,nor is it an economical gas storage option for Southcentral.Therefore,the Task Force opposes the ANGDA Spur Line project. 8.3 ENSTAR Bullet Line ENSTAR has been a natural gas utility in the Anchorage area since 1961.Today it has 3,100 miles of gas transmission pipelines and distribution mains serving more than 128,000 customers in Southcentral Alaska:more than 345,000 Alaskans.ENSTAR has committed substantial dollars and resources to its Bullet Line project and announced a corporate commitment of $1 billion in support of its Bullet Line project. ENSTAR claims that it would participate in project financing and would utilize a debt-to-equity ratio of 75 percent to 25 percent,which for the approximately $4 billion project would equate to borrowing about $3 billion and investing $1 billion in equity.ENSTAR's owner is prepared to commit to providing the equity financing once the project is deemed economically viable and has received all the necessary support and approvals from various governmental agencies. However,ENSTAR must solve some problems with gas reserves,pipeline routing,and gas vdume (tariff on delivered gas)before the project can succeed.For example: 1.Gas Supply:ENSTAR needs to secure at least 3 Tcf of gas reserves to make its Bullet Line economical.The Gubik gas reserves are not yet defined.Today,there is only one gas basin in production with enough known reserves to support a 0.5 Bef/d bullet line,and that is the Prudhoe Bay Unit on the North Slope. In-State Gas Pipeline Supply Options Study Page 53 2.Studies,Permits,and Rights-of-Way:ENSTAR will need approval to construct a pipeline across State,Federal,Native and other private lands-especially parks and preserves- located along its proposed pipeline route.Securing permits for this pipeline corridor could cause delays in the ENSTAR project. 3.Gas Volume:The ENSTAR Bullet Line proposal is estimated to cost $3.8 billion and will require a substantial gas demand from industrial end-users if it is to provide an affordable pipeline tariff for Southcentral and Interior consumers.Currently,ENSTAR charges $10.46/Mcf for natural gas delivered to its residential and commercial customers in Southcentral.As with similar enterprises,ENSTAR anticipates that the cost of gas delivered through the Bullet line to Southcentral and the Interior will be a function of: a.the prevailing market price for gas negotiated with gas owner{s], b.the cost of its transportation from wellhead to the customer,and c.aregulated rate of return granted to the pipeline owners. Cost of transportation (tariff)is a function of line construction costs and volume.ENSTAR bases its analyses on an assumed gas through-put volume of 0.5 Bcf/d.The current total residential, commercial,and utility demand within the Railbelt is approximately 0.2 Bcf/day.Therefore, development of substantial industrial markets,in addition to increased residential and commercial market demand,will be necessary to make the project economical. Also,Interior Alaska should be concerned that ENSTAR is proposing to build the Bullet Line passing 40 miles west of Fairbanks.The project includes a 12-inch lateral line to deliver up to 30 Bcf/y to Fairbanks.The 690-mile Bullet Line tariffis estimated to be $2.50/Mcf based ona gas . flow rate of 0.5 Bcf/d delivered to Southcentral.The Regulatory Commission of Alaska may require the 12-inch lateral line to have a separate tariff,which could make gas delivered to the Interior more expensive. ConclusionENSTARisa private company and is prepared to commit $1 billion toward building the Bullet Line.ENSTAR will decide whether to sanction this project by 2010,by which time it should have considered the above listed concerns.The Bullet Line may have potential for delivering natural gas to Southcentral and Interior Alaska within the next eight years,but unanswered questions regarding its cost of delivered gas leave the viability of the project in question: e ENSTAR considers Toolik Lake the northern terminus of its line.Toolik is 87 miles from the Gubik area and 136 miles from the Prudhoe Bay Unit.The cost of completion of the Bullet Line from Toolik to a gas supply should be factored into project costs and tariff estimates. e ENSTAR estimates it will save $100 million by routing the Bullet Line to the west of Fairbanks by 40 miles,as opposed to coming directly through Fairbanks.That $100 million is equivalent to an additional 2.6 percent project cost.If the additional 2.6 percent were added to ENSTAR's current estimated tariff of $2.50,the new tariff would be $2.65 delivered to Cook Inlet.The cost of the 40-mile lateral line has yet to be determined and the line tariff impact on the transportation tariff must be understood before Anchorage and Fairbanks can assess which configuration will best achieve their mutual benefit. e Gas volume through the ENSTAR proposal will require roughly 0.3 Bcf/d of additional throughput for which there are currently no existing customers.We believe that the Bullet Line will require ENSTAR to find industrial users who would negotiate with either gas In-State Gas Pipeline Supply Options Study ;Page 54 owners (to reduce wellhead price)or pipeline owner (to reduce tariff)or both before the Bullet Line will be economical. 9.Recommendations 9.1 In-State Gas Supply Each of the in-state gas distribution proposals we reviewed faces challenges and do not,as standalone enterprises,appear to satisfy Alaskans'energy timeliness and affordability requirements.They also do not resolve Fairbanks'significant air quality health issues.However, each contains components that,if aggregated,could provide Alaskans with affordable energy and mitigate air quality issues in an acceptable timeframe. Recommendation #1 The Stafe should provide leadership and facilitate a collective effort of the interested private and public entities. It is also in the State's capacity to improve the economics of any in-state gas distribution system by actively participating in the project,through direct funding support or through use of its bonding authority.Affordable clean energy is an important issue to all Alaskans:Southcentral needs peak gas storage but faces declining gas fields,Fairbanks has alarming air quality problems,and Rural Alaska is staggering under high energy costs.All of this,coupled with Alaska's critical need for timely and affordable energy for all of its residents,should be the catalyst for the start of a new chapter in the distribution of Alaska's wealth:energy. Recommendation #2 The State should participate in funding the construction of an in-state gas distribution system. This effort should accomplish the construction of an in-state bullet line from Cook inlet fo a viable gas supply and the construction of a North Slope LNG piant as expeditiously as possible. The bullet line could deliver gas to the Railbelt as early as 2016.In the interim,an LNG/LPG plant could deliver gas to Fairbanks and other Alaska communities via road,rail,or marine transport.It could also supply Rural Alaska with a source of propane.When the bullet line is complete,the LNG plant could continue to supply Rural Alaska with propane from North Slope gas,or could be relocated to a more efficient supply of natural gas and continue with propane and LNG distribution. Recommendation #3 e The State should fund the Alaska Energy Distribution System.This system would be a corridor for energy to cornmunities located in economic reach of the delivery system and, through the tariff,be a revenue-generating enterprise. e For those communities not located within direct reach of the delivery systern,the State should direct a portion of the transportation tariff fo fund an Alaska Energy Cost Reduction Program.This program could provide funding for LNG/propane distribution,renewable and/or sustainable energy infrastructure,and power cost equalization programs. Current total Railbelt commercial and residential demand for gas appears to be too low to achieve the economies of scale necessary to allow any of the proposed in-state natural gas In-State Gas Pipeline Supply Options Study Page 55 distribution proposals to supply gas on a cost-competitive or "affordable”basis.Though Southcentral's gas market is well established and substantial;it is not sufficient on its own to justify construction of an economically sized bullet line.It is only by boosting natural gas demand across the entire Railbelt that a bullet line to Southcentral can be made economical. Recommendation #4 e The Fairbanks North Star Borough (FNSB)should assist FNG in the construction of its distribution infrastructure.The goal should be an accelerated build-out of its in-ground main and feeder line gas distribution system targeted af 10 BctYy for residential,commercial,and industrial customers prior fo a 2015 bulfet line startup.Ata minimum,the FNSB should assist FNG with easements and rights-of-way to help facilitate the build-out. e Local governments of communities along the bullet line route and road system (such as Healy,Delta Junction,Tanacross,and Giennallen)should establish a similar,simultaneous build-out program.Due fo the relative size and potentially limited financial resources of these communities,the State should be prepared to assist these efforts,if if proves necessary. e For those communities accessible by other appropriate corridors (including road,rail,and marine transporf),the State should also direct ifs agencies to partner with appropriate Statewide and/or local entities for the aggressive testing and installation of "distributed gas systems'suitable for use in non-Railbelt communities or disconnected residential and commercial clusters. In-State Gas Pipeline Supply Options Study Page 56 Attachment 1 Future Price of Energy Dr.William Sackinger Growth of the world economy is expected to continue over the above-mentioned 50-year period, with economic growth composed of productivity increases and also inflationary increases.A conservative estimate of the rate of inflationary increase is 2.5 percent per year,which has been the target for control of inflation by the major central banks of the world economy for many years.Oil,and other goods and services,may be expected to increase at this rate of inflation. One should also consider that world oil is sold for U.S.dollars,but that the goods imported into the oil-producing countries are manufactured in many other countries,using many different currencies.Therefore,there is the tendency for the value of the U.S.dollar to decline in the foreign exchange markets,as this oil-for-goods trade imbalance continues.In general,the U.S. is a debtor nation,a condition that reaches beyond oil and is related to the unfavorable trade balance of the U.S.,which has persisted for most of the years in the past four decades.These two factors,then,together with the 2008 decision of the U.S.Treasury and the U.S.Federal Reserve system to create new money to combat the depression of 2008/9,means that the foreign exchange value of the U.S.dollar can be expected to continue to decline.According to the Federal Reserve Bank of St.Louis (2008),Figure A-1,the decline rate of the dollar over the past six years has been 5.13 percent per year,and this decline may be assumed to continue indefinitely.However,substantive changes in U.S.economic policy could possibly reduce this foreign exchange imbalance,and it seems reasonable to consider that it might be reduced to as low as 3 percent per year under circumstances of careful management of trade imbalances and debt issuance.The foreign exchange effect on the price of oil should also be considered,within this range of 3 percent per year to 5.13 percent per year. In its recent World Energy Outlook,the International Energy Agency (IEA 2008)has warned that there is a continual depletion of the world oil reserves,at about 7 percent per year.In addition, there has been a historical growth rate of about 2 percent per year in demand for oil,due tothe emerging nations and their growing populations of young consumers,and their demand for individual transportation vehicles.If the substitution of natural gas and coal in the energy profiles of these nations increases,this demand growth may drop to the range of 1%per year,as has been assumed by IEA (2008)and by ExxonMobil (2008).Nevertheless,the demand for transport fuels will relentlessly increase,and new oil resources must be brought to production, at the minimum rate of 8 percent each year,if demand and supply are to be kept in balance. This is a formidable challenge,and it has been pointed out (Sackinger,2006)(IEA,2008)that there will be a shortfall between oil demand and oil supply as early as 2013,with a need for transportation fuels to be produced from unconventional sources (for example,Gas-To-Liquids and Coal-to-Liquids)by 2014 and further onward into the indefinite future.This shortfall is caused by the fact that the swing producer of OPEC,Saudi Arabia,has a limited capacity for expansion,set by the huge investments required and the difficulty of bringing new and high- producing oil fields on line.Other countries in OPEC and in non-OPEC are operating at maximum capacity,on an annual average basis,and cannot be expected to find 8 percent per year of new oil and bring it into production.There is thus an expected sharp upturn in world oil In-State Gas Pipeline Supply Options Study Page 57 price to be expected in 2014 from this forecasted economic condition of demand/supply imbalance.The imbalance has been also predicted by IEA (2008). It is therefore useful to construct a table of probable supply and demand,and price,for world crude oil,as shown below.Estimates are taken from OPEC and from IEA.All numerical values are projections only,with no better than +/-20 percent confidence levels. Figure A-1:Projection of Oil Demand,Supply,and Price (2009-2059) Combination Chart: PROJECTION OF OIL DEMAND,SUPPLY,Mill. bbl/day*AND PRICE,2009-2059 9S4¥}}H L f f 1 t ) >t t t +t t t H f 4 > wom Avg.Price --=--Demand* AN) -a-Supply oeConventional* some Supply Uncenventional* 07 ™y 2009 2014 2019 2024 2029 2034 2039 2044 2049 2054 2059 The investments required to create non-conventional oil from natural gas or coal feedstocks are in the range of $80,000 to $160,000 for each barrel/day of unconventional oil to be produced (measured in dollars in 2009).The advantages of making investments in equipment to produce unconventional oil,sooner rather than later,are: 1.The production cost of the unconventional oil is known and locked in for the life of the plant and the long-term price of the feedstock source. 2.Natural gas can be expected to have a market value closely following crude oil,and so can be a basis for financial flows to the gas owners through sales,rather than simple combustion within Alaska. 3.Coal reserves are monetized and changed into non-conventional oi!(Coal-To-Liquids processes),and the product price can follow the world crude oil market price,if exported. In-State Gas Pipeline Supply Options Study Page 58 4.Conventional oil and gas can be marketed at prevailing world higher prices as long as the pipelines are capable of delivery. 5.The construction costs of conversion plants for producing non-conventional oil will only escalate,dramatically,after 2013.it is for these reasons that most of the major corporate organizations in the field of non-conventional oil (from gas or coal)wish to take an equity interest in any plant built today.Today,China is building 17 plants to gasify coal,most of them to produce petrochemicals but at least one to produce non-conventional oil. In-State Gas Pipeline Supply Options Study Page 59 James Strandberg Subject:Respond to Robert V on agenda Start Date:Monday,February 02,2009 Due Date:Monday,February 02,2009 Status:Not Started Percent Complete:0% Total Work:0 hours Actual Work:0 hours Owner:James Strandberg