ECON 323.docx

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University of Calgary
ECON 327
Ronald Schlenker

ECON (Sept. 19, 2013) 1.Hydrocarbons-class of organic compounds consisting only carbon (C) & hydrogen (H) 2. Petroleum-general term for gaseous (natural gas) & liquid (crude oil) hydrocarbons 3. Components of natural gas a) methane (CH4)-largest component -main use is as a fuel -also a petrochemical feedstock/fertilizer b) natural gas liquids (NGLs) i) ethane (C2H6)-usually second largest component -petrochemical feedstock ii) propane (C3H8)-fuel/petrochemical feedstock iii) butane (C4H10)-fuel/feedstock iv) pentanes plus (C5+)-key diluent for oilsands products in Alberta v) ethane/propane/butane can be left in gas stream & sold as gas (on heat equivalent basis), more valuable if upgraded (Table 1) vi) pentanes plus usually removed at gas plants for value/operational reasons c) other components i) hydrogen sulphide (H2S)-if present, gas is called sour gas -removed for safety, operational, environmental reasons ii) carbon dioxide (CO2) iii) nitrogen (N2) iv) helium (He) 4. Natural Gas Prices a) trading hubs-area with multiple pipeline interconnections and/or access to natural gas storage facilities which allow many trading options for buyers & sellers i) producing hubs Ex. Henry Hub, Louisiana AECO-C, Alberta ii) market hubs Ex. Henry Hub New York AECO Malin Chicago Topock b) netback price-market price minus transportation cost to market Ex. See paper notes -in fully integrated, competitive gas market, price of gas in different regions should differ only by transportation costs c) AECO vs. Henry Hub prices-Figure 1 & Table 2 -transportation costs from Henry Hub to Chicago < AECO to Chicago, therefore netback at AECO should be & has been lower -90's low prices $1-3/mmBtu -2000-08 high prices $4-9/mmBtu -2009-13 low prices $3-4/mmBtu d) consumer prices -includes cost for commodity gas & delivery cost e) gas vs. oil prices (Figure 2) i) oil price history 1920-70's $1-3/bbl 1973-Arab/Israeli War; embargo $3-$12 bbl in late 1973 1979-second big price spike $20-$40/bbl in 1979 (Iranian revolution) 1986-price collapse in 1986; below $10/bbl 1987-99 $15-20/bbl 2000-08 better OPEC discipline, fast growing Asian demand $147/bbl July 2008 2008-09 financial crisis $35/bbl March 2009 2010-13 $80-100/bbl ii) prior to 1973, gas price < 40% of oil price 1973-2000 40%-80% Early 2000s, some years, prices equivalent Lately, gas valued at 20% of oil price 5. Resource & Reserve Concepts a)Original Resources in Place-gross volume of hydrocarbons initially in a reservoir before any production & without the regard for the extent to which volumes will be recovered b)Proven Reserves-reserves recoverable under current technology and present & anticipated economic conditions, specifically demonstrated by drilling, testing or production c)Probable Reserves-portion of reserves contiguous with proven reserves that are interpreted to exist with reasonable certainty d)Initial Established Reserves (IER)-proven reserves plus probable (AER) or half of probable (NEB) or other e)Remaining Established Reserves (RER)=IER-Cumulative Production -see paper notes for diagram f) Future Additions to Existing Pools-future enhanced oil recovery (EOR), extensions of resource estimates with new info. g) Discovered Recoverable Resources=IER + Future Additions h) Undiscovered Recoverable Resources-recoverable based on available geological & geophysical evidence but that have not yet been shown to exist by drilling/testing/production i)Ultimate Potential-all resources that may become recoverable having regards for geological prospects & anticipated technology j) recent estimates (Table 4) (Conventional 28%) (Bitumen 12%) 6. Categories of Natural Gas a) raw gas-mixture of methane, NGLs, H2S, CO2, etc… b)marketable gas-mixture of mainly methane originating from the processing of raw gas that meets specifications for use as a fuel or industrial raw material c)solution gas-gas that is dissolved in crude oil under initial reservoir conditions & emerges as a result of pressure & temperature changes d)associated gas-gas in a free state in communication with crude oil at initial reservoir conditions e)non-associated gas-gas that is not in communication with crude oil at initial reservoir conditions f)sweet gas-gas with 0.01% H2S or less g)sour gas-gas with more than 0.01% H2S h)Alberta distribution-Table 5 -predominantly sweet & non-associated i)unconventional gas i) coal bed methane (CBM)-methane found in coal seams ii) shale gas-methane adsorbed on surface area of shale iii) gas hydrates-methane molecules trapped & encased by ice molecules (found beneath permafrost, ocean bottoms) OVERVIEW OF WORLD GAS MARKETS 1.Reserves-Table 6 a) by region Middle East 43% Europe/Eurasia 31% b) by country 1 Russia 19% 2 Iran 18% 3 Qatar 13% 4 Turkmenistan 9% 5 USA 5% 18 Canada 1% c) over time -in last 20 years, remaining reserves up by about 65% 2.Production a) production & reserves very different b) by region-more balanced than reserves Europe/Eurasia (includes Russia) 31% North America 27% Middle East 16% Asia Pacific 15% c) by country 1 USA 21% 2 Russia 18% 3 Canada 5% d) over time -world production has risen from 40 Tcf in 1973 to about 120 Tcf in 2012 (about 2-3%/year) -Middle East has rapidly emerged in last 20 years, now about 15% North America about 25% Europe/Eurasia low 30% e) reserves-to-production (R/P) ratio-see Table 7 World 55 Europe/Eurasia 56 North America 12 Middle East 146 Asia Pacific 31 Second Lecture 3. Consumption-Table 9 a) by region-match production Europe/Eurasia 33% N America 27% Asia Pacific 19% Middle East 12% b) by country 1. USA 22% …7. Canada 3% 2. Russia 13% -proximity of production, climate, economic activity are factors c) per capita consumption highest in Canada/US/Russia/Saudi/Turkmenistan/Uzbekistan/Netherlands 4. Trade a) in 2012, 37 Tcf of 119 Tcf of gas produced was exported (about 30%) b) roughly 70% of exported gas pipelined, 30% in liquefied natural gas (LNG) form c) leading exporters (Table 10) 1. Russia 19% 2. Qatar 12% (leading LNG exporter) 3. Norway11% 9. Canada 8% d) leading importers (Table 11) 1. Japan 12% 2. USA 9% 3. Germany 8% Canadian Gas History 1859/60- gas discovered in New Brunswick/Ontario 1883- gas discovered in Medicine Hat AB 1885- Bunsen Burner invented 1890- gas used for cooking, heating & lighting in Medicine Hat 1894- well drilled in Athabasca (NE AB) searching for oil; gas found instead, blowout flowed for 21 years 1904- gas discovered at Suffield AB 1909- gas discovered at Bow Island, AB in 1912, 270 km pipeline built from Bow Island to Calgary 1923- 130 km pipeline completed between Viking & Edmonton 1924- second major find at Turner Valley (SW of Calgary)- Royalite #4 flowed 600 barrels/day naphtha & 21 mmcf/d of gas- gas was flared -first gas plant to scrub 2 S natural gas built in Turner Valley 1938- Alberta government brings in Oil & Gas Conservation Act creates Energy Resources Conservation Board (ERCB) (now Alberta Energy Regulator) 1941- gas pipelines subject to Utilities Act- regulated tolls 1944- sour gas discovered at Jumpingpound AB 1947- oil discovered at Leduc, south of Edmonton- set off boom 1951- ERCB given authority over gas removal permits from Alberta 1952- first sulphur extraction plant completed by Shell at Jumpingpound 1954- AB government sets up Alberta Gas Trunk Line (AGTL, eventually NOVA, NGTL, TCPL Alberta) as monopoly over long-distance gas transmission in province 1957- Westcoast Pipeline Connecting NE BC/NW AB to lower mainland BC & U.S. Pacific Northwest starts up 1958- TransCanada Pipeline (TCPL) connecting AB to Ontario starts up 1959- National Energy Board (NEB) formed by federal government- regulator of interprovincial pipelines 1961- Alberta government institutes air quality standards including limits on SO 2missions 1962- gas shipments between AB & California 1964- first straddle plant built at Empress AB 1965- Great Lakes Gas Transmission (GLGT) linking Cdn gas to U.S. Midwest 1972- gas discovered in Mackenzie Delta, NWT & offshore Nova Scotia 1973- federal government introduces price controls on oil & gas 1975- methanol plant built at Medicine Hat; AB government support for ethane-based petrochemical industry 1979- first ethylene plant at Joffre starts up 1980- National Energy Program (NEP) introduced by federal government- price controls, revenue taxes 1981- TransQuebec & Maritimes (TQ&M) pipeline starts up; start of foothills pipeline connecting AB to Midwest & Pacific Northwest 1982- major declines in exploration/development activity in Western Canada 1985- Western Accord signed between federal & provincial governments; end of NEP & beginning of deregulation 1986- gas discovered at Caroline 2000- Alliance pipeline connecting NE BC/NW AB to Chicago starts up Origin of Natural Gas 1. Formation of Oil & Gas a) abiogenic- hydrocarbons were trapped inside the earth as it formed problem- preponderance of hydrocarbons in sedimentary rock b) biogenic- organic material was deposited in sediments which became buried- as depth of burial increases, heat & pressure transform organic matter to hydrocarbons c) coal- derived from land plants d) oil- derived from marine plants & animals e) natural gas- derived from either land/marine plants/animals subject to higher pressures/temperatures f) once oil or gas is formed, pressure forces the hydrocarbons through permeable rock layers until it is trapped in a porous sedimentary rock like sandstone or limestone g) broad categories of traps i. structural- result from faulting & folding of rock ii. stratigraphic- changes in permeability of neighbouring rock 2. Reservoirs in Alberta a) Geological time scale Era Period Age (million years) Cenozoic Quaternary 1.8 Tertiary 65 Mesozoic Cretaceous 136 Jurassic 195 Triassic 225 Paleozoic Permian 280 Mississippian 345 Devonian 395 Cambrian 570 Pre-Cambrian b) oil & gas in AB found throughout Mesozoic & Paleozoic source rock c) Cretaceous sandstones & Mississippian/Devonian limestones d) Cretaceous Devonian Mississippian IER 58% 18% 18% RER 70% 12% 11% Ownership of Resources 1. Surface Rights- rights to work on the land surface -surface access agreements negotiated with landowners -usually separated from mineral rights 2. Mineral Rights-rights to explore for & produce resources below the surface -mineral rights may be owned by i) provincial or federal governments (Crown rights) ii) First Nation bands iii) freeholders 2. Canada Mineral Rights History 1670-King of England granted all surface & mineral rights for lands draining into Hudson’s Bay to the Hudson’s Bay Company (HBC) 1867-Dominion of Canada formed (ONT, QUE, NS, NB), each province retained ownership of onshore natural resources 1869-HBC made deal with Dominion of Canada, retained 1/20 of the land surveyed & settled over the next 50 years in the southern prairies -HBC received about 20,000 in a patchwork throughout Western Canada Diagram showing a township, which is 6 miles by 6 miles -start at lower right corner and number going left, then up, then right -HBC kept numbers 8 and 26 -offspring of HB Oil & Gas still holds 8000 today -Crown held 95% of surface/mineral rights in southern prairies & all rights in other unsettled areas 1881-Canadian Pacific Railway (CPR) granted 100,000 -EnCana/Cenovus have 44,000 today 1887-Crown would in future retain mineral rights in the Northwest Territory; previously settlers retained these rights -greater amounts of freehold land in MB (75%) vs. SK (20%) vs. AB (10%) 1930 rights transferred from Dominion of Canada to provinces of AB, SK & MB; Dominion retained rights in Territories & Hudson’s Bay 1985/86 accords signed between Federal government & provinces of NFLD & NS regarding revenue sharing/resource management 2013 devolution of powers to territorial governments by Federal government -every question will have a question referring to it (Sept. 26, 2013) Third Lecture Exploration & Development Activity 1. Mineral Right (Land) Acquisition a) government have Crown land sales where companies bid on mineral rights b) companies make economic calculations of projected revenues & costs to establish a reasonable bid for the land payment for the land or bonus payment c) companies can negotiate directly with freehold landowners d) in AB, about 90% of land related expenditures go to Crown, 10% to freeholders e) in frontier regions, development plans are also sometimes submitted to governments f) when oil or gas produced, landowner receives a royalty 2. Geological & Geophysical Activities a) geological info obtained via: i) land surface surveys ii) analysis of magnetic fields, gravity & radiation b) main geophysical activity is the seismic waves-transmit acoustic energy into the earth & record energy reflected back as seismic waves from subsurface geological boundaries i) 2D seismic-line of receivers yield cross-sectional view ii) 3D seismic-grid of receivers yield 3D image iii) 4D seismic-3D over time iv) each step up yields much more info but at significant cost 3. Drilling a) wellsite preparation b) rig set-up c) drill & cement surface hole d) drill main hole e) test/evaluate prospective producing formations i) wellsite geologists constantly monitoring cuttings ii) core samples sometimes taken iii) wireline logging-get info about zone thickness, porosity, permeability, zone fluid composition, etc. iv) drills tem testing-isolate zone, sample fluids/flow rates/pressure f) abandon or case well-compare expected revenues to yet to be incurred costs i) if well is a dry hole, cement wellbore & reclaim site ii) if well is a potential producer, install production casing (pipe) & cement it in place 4.Completion a) perforation-shoot holes through casing b) stimulation-increase permeability of producing formation i) fracturing ii) acidizing 5. Field Equipment & Facility Installation a) wellsite facilities i) wellhead ii) pumpjacks/compressors b) flowlines & gathering lines c) gas plants-facilities that process natural gas; includes equipment that removes: i) water ii) CO 2 iii)sulphur iv) NGL’s 6. Exploration & Development (E&D) Expenditures a) recent data for AB/Canada (Table 12) conventional oil & gas -about $25-30 B annually in AB in recent years -for AB, conventional E&D spending has represented about ¼ to 1/3 of overall investment & about 10% of GDP -roughly 2/3 of national spending in AB b) trends over time-Figure 3 i) after steady increases from 1947-56, spending levelled out from 1956-73 between $2- 4 B per year ii) oil/gas price increases in 70s led to enormous growth through 1980 iii)NEP in 1980 & price collapse in 1986 lowered spending iv) expanding markets, depletion of reserves & high prices boosted spending significantly until 2005/06 v) very high unit costs from 2006-08 lowered activity vi) from 2009 on, financial crisis and shale gas production increases led to massive declines c) exploration vs. development spending -as basin matures, proportion of E&D spending that is development tends to increase (about 75% development recently) d) trends in components of E&D spending-Figures 4&5 i) geophysical & land shares decrease over time as much info gained, more land bought up ii) development drilling & field equipment dominate development spending e) trends in emphasis on gas vs oil -Figure 6 -opening up of markets in 60s led to more gas directed drilling for several years -relatively even split in 80s, early 90s -from late 90s until 2008, about 80% of conventional wells were gas directed -with gas price collapse with shale gas/recession, far more oil directed drilling since 2009 f) production levels were maintained via massive drilling up until 2007; with lower gas prices from 2009 on, # gas well drilling has plummeted to less than 1000 last year (vs 14000 in 2005) (Figures 7 & 8) -since 2007, production has dropped by about 5% per year with lack of E&D spending g) unit E&D costs & unit gas & by-product revenues (Figure 9 & Table 13) -long term trend of rising unit E&D costs as basin matures BUT in bad times, will have periods where unit costs decline (only going after low cost prospects) -much more E&D activity when revenue-cost spread is high (79, could be 74-86, 00-08) vs low Production & Operating Activity 1.Operating Costs a) costs associated with operating the wells, gathering systems & gas plants/oil batteries b) recent data for AB Billion $/mcf equivalent 2005 $ Operating 7.2 1.05 E&D Costs 18.5 3.20 -for conventional oil & gas, operating costs relatively small vs E&D costs c) real unit operating costs tend to increase over time as basin matures (Figure 10) d) technological improvements may slow/reverse trend e) when real prices are steady/falling, real unit operating costs often fall -companies more creative, shut down high cost wells 2. Royalties a) usually Crown or freeholder receives royalty on production b) royalties are often sensitive to a variety of factors i) vintage ii) productivity iii)price iv) length of production c) AB’s recent royalty schemes -1993-2008 -let R%=royalty rate -graph with R% on y-axis and Price on x-axis -Floor rate of 15% until hit the Select Price, then the graph will slope up, but tail off a little bit, until hits the Ceiling Trigger Price, which was 30% (New gas post-1973), 35% (Old gas, pre- 1973) -royalty regime designed for low gas prices, producers getting profits when prices increased -lack of price sensitivity when price reached ceiling trigger price -in the 2000’s, prices were generally so high that the ceiling royalty rate was the only relevant rate (no price sensitivity as prices rose & rose) -in addition, low productivity (LP) wells had reduced royalties -let ADP=average daily production in 10 m /d 3 R LPR%-[(R%-5)*(16.9-ADP/16.9) ] 2 When ADP less than 16.9% -minimum rate=5% -LP adjustment applied to greater than 90% of wells by 2005 -ceiling rate of 30% reduced to effective rate of 22% by 2005, 20% by 2007 (Table 15) -gross royalty rate further reduced by capital cost/operating cost/processing fee allowances -with all the adjustments, effective royalty rate (Fig 11) dropped from 18% in 2001/02 to 13% by 2007 despite gas prices being around $7/GJ from 2004-07 vs $4/GJ in 2001/02 -government changed royalty system Current System R%=price component + quantity component = p + rq -either p or q could be negative (ie. with very low prices or very LP) but minimum R% is still 5% -maximum R% goes to 50% (vs. 30%) -additionally, depth factor adjustment introduced to lower royalties on more expensive wells -system adopted in 2008; effective rate went up in 2008 when gas price was still high (Oct. 3, 2013) Fourth Lecture Natural Gas Transportation 1. Stages of Transportation a) Gathering-from gas plant to long-distance to long-distance transmission line b) Transmission-from gathering system exit to consuming region, usually over relatively long distances c) Distribution-from transmission system exit to consumer 2. Transportation Costs a) Pipelines-most common method i.material costs include pipe, compression, meter stations, valves/fittings, etc. ii.non-material costs include installation, engineering, etc. iii.material/non-material split depends on climate, terrain, stage of development, etc. iv.illustrative costs below CBillion 2003$ Costs Foothills Alliance Proposed Mackenzie Valley Materials 1.1 2.1 1.3 Non-Materials 1.0 1.7 2.0 2.1 3.8 3.3 Length (miles) 640 1860 790 Capacity (Bcf/d) 3.3 1.6 1.2 MM$/(Bcf.d/mile) 1.0 1.3 3.5 -very costly, typically take several years to build + planning/regulatory stage b) tanker-usual method for liquefied natural gas (LNG) i) tankers that carry about 3 Bcf cost about $200-250 mm Cdn ii) also require: liquefaction facilities: -1 Bcf/d plant costs about $4-5 B Cdn storage facilities regasification facilities ii) advantages include ample international supplies, low volume/flexible storage iii) disadvantages cost, safety 3. Characteristics of Gas Transmission a) Capital intensity-cost of capital is a major component of total cost b) Durability-expected service life of 25+ years c) Sunk nature of capital-money spent, cannot be redeployed to other activity d) Hold-up problem-one side of the market has more alternatives than the other, can threaten to leave thereby stranding the other side’s investment -long-term contracts partially mitigate problem but offer incomplete protection e) natural monopoly-unit costs minimized by concentrating production in a single firm i) economies of scale-average costs (AC) decline as output increases ii) economies of scope-reduction in costs when a group of products or services is produced by a single firm vs. multiple firms iii)network economies-single firm more likely to optimize network configuration, management of network -example -pipe volume is proportional to radius (r) , pipe cost is proportional to pipe circumference (& r) & to wall thickness -installation costs; many depend on pipe diameter & others do not increase proportionally with volume -right of way costs; very small increase in excavation & right of way width with increased pipe size -design/survey/regulatory costs largely independent of pipe size -illustrative costs for 200 km pipeline A B B/A Diameter (in) 12 24 2.0 Capacity (mmcf/d) 50 200 4.0 Costs (mm$) Design/Survey/Regulatory 5 5 1.0 Right of Way 5 6 1.2 Installation 30 60 2.0 Materials 20 60 3.0 Total 60 131 2.2 MM$/(mmcf/d) 1.20 0.66 0.55 4. Rationale for Regulation a) Achieving productive efficiency is main goal-may involve prohibiting inefficient entry Graph showing $/unit on y-axis and Quantity (Q) on x-axis D=AR is the demand curve going the usual way MR is the marginal revenue curve and it goes to same way, but its slope is greater MC is the marginal cost curve and it curves a little bit the normal direction (AC is the average costs curve and it curves above the MC curve, but it points in the same direction as the demand curves a) Unregulated monopolist would set MC=MR, produce Q , chargu P , make euonomic profits in long run (P -AC )*Q =shaded box u u u -unregulated monopolist will restrict output thereby reducing society’s surplus b) Competitive or socially optimal outcome would have allocative efficiency (P=MC) -output=Q &sprice =P s -monopolist cannot cover costs Loss=(AC -s )sQ =snother shaded box c) Regulator must choose a price that maximizes society’s surplus subject to a break-even constraint for the firm -solution-set P=AC & is called regulated/fair return or Ramsey (Pr & Qr in diagram) pricing -Comparison of surplus under various alternatives -another graph Social Optimum Unregulated Fair Return Consumer Surplus A+B+C+E+F+G A A+B+C Producer Surplus none B+E E+F Total Surplus A+B+C+E+F+G A+B+E A+B+C+E+F Deadweight Loss none C+F+G G -Second best solution is fair return pricing d) Ramsey pricing with multiple products/services -let i=price elasticity of demand in market i [P-MC 1P 1 E i [P-MC /2 ]2E 2 -relative price distortion in each market should be inversely related to elasticity of demand; lower markup over marginal cost with higher elasticity -two graph comparison -raising price by same degree in both markets results in much greater surplus loss in elastic market -problems i) identifying demand & cost functions ii) allocating common costs between markets iii)essentially, price discrimination, violation of various tolling criteria typically used by regulators 5. Regulatory Objectives & Criteria a) Objectives i)efficiency ii) cost reductions benefit consumers iii)economic viability/sustainability iv)fairness/equity v)minimize regulatory burden vi) minimize implementation problems b) Criteria i)tolls should be just & reasonable with no unjust discrimination -equal tolls for same service -no acquired rights -tolls based on cost causation ii) rate stability iii)encouragement of efficiency iv)revenue sufficiency/stability v)consistency with other policies/regulation vi) practicality, administrative simplicity & general acceptance 6. Traditional Cost of Service (COS) Regulation a) Pipeline is allowed to cover all of its explicit expenses & earn a fair rate of return on invested money b) Rate base (RB)-depreciated capital cost & working capital -only prudently incurred costs are allowed in rate base c) Rate of Return (r) depends on regulator approved capital structure (debt/equity mix), return on equity (re) & the cost of debt (d ) -let d=debt proportion of financing e=equity proportion of financing Ex re=0.10 e=0.4 rd=0.06 d=0.6 r=d*rd+e*re r=0.06*0.6+0.1*0.4=0.076 (7.6%) d)return component of cost of service (R)=r*RB e) depreciation (D)-expense for capital used up in production process -many ways to depreciate assets -common method is straight-line depreciation f) operating & maintenance expenses (O&M) g) municipal taxes (MT) h) income taxes (IT) i) cost of service (COS)=R+D+(O&M)+(MT)+(IT) Ex. Starting Rate Base=$1 Billion=$1000 Million 25 year life, straight line depreciation Annual O&M=$35 million Annual MT=$10 million Income tax rate=40% of return on equity Rate of return on Rate base=7.6% Find COS in year 1 & year 2 D=1000/25=40 million End of Year 1 Rate Base=1000-40=960 Mid Year Rate Base for Year=(1000+960)/2=980 Return=R =180*0.076=74.48 MM IT=0.4*980*0.1*0.4=15.68 MM Tax rate e e COS=74.48+40+35+10+15.68=175.16 MM End of Year RB in Year 2=960-40=920 Mid Year RB in Year 2=(960+920)/2=940 R 20.076*940=71.44 IT2=15.04 COS =21.44+40+35+10+15.04=171.48 j) price of transportation or toll is COS (or revenue requirement (RR)) divided by volume Q Ex. Suppose 1 Bcf/d is the volume per unit toll (year 1)=($175.16 MM/year)/(1 Bcf/d*365 d/yr)=$0.480/Mcf k) Straight fixed variable (SFV) toll methodology-fixed costs are recorded via a demand toll; variable costs are recovered via a commodity toll Ex. Suppose 20% of O&M are variable, everything else is fixed 35 MM*0.2=7 MM/yr -commodity toll= (7 MM/yr)/(365 Bcf/yr)=$0.019/Mcf -demand toll= (168.16 MM$/yr)/(365 Bcf/yr)=$0.461/Mcf -demand charge in based on contract capacity & is paid regardless of whether contract volume is shipped or not -load factor (LF) = (actual volume/contract volume)*100 Ex. At 90% LF Demand toll=(168.16/365)/0.9=0.461/0.9=0.512 Total toll=0.512+0.019=0.531 At 50% LF Demand toll=0.461/0.5=0.922 Total toll=0.922+0.019=0.941 -midterm will cover first five lectures (11 to 13 questions per lecture), all MC October 10, 2013 Lecture 5 Ex. TCPL Tolls ($/GS) Demand Toll Commodity Toll 100% LF Toll 80% LF Toll AB/SK Border 0.402 0.018 0.420 0.520 (Empress) to Emerson MB Empress to Eastern Zone (Ontario) 1.114 0.055 1.169 1.446 l) sample of service offerings i) firm service-shipper contracts to get access to specific volume on pipeline; pays fee to reserve space (demand charge) and another charge for gas actually shipped (commodity charge) ii) interruptible service-available when there is excess capacity; pays fee per unit of gas shipped 7. Issues with Traditional COS Regulation a) Front-end loading -graph showing downward sloping curve labelled Current $ with Time on x-axis and $/mcf on y-axis -Constant $ curve also downward sloping curve, but underneath Current $ curve -not a big issue if this reflects actual costs, but in many unregulated industries this pattern is not observed b) potential solutions-change the depreciation pattern -“levelized tolls” are constant over time 6. incremental vs rolled-in tolling for expansions i) expansion cost/volumes dealt with separately under incremental (vintage) tolling ii) under rolled-in, all expansion costs put into single, existing rate base iii)incremental tolling involves price discrimination for identical service based on acquired rights notion iv)rolled-in tolls have become favoured due to: -no price discrimination -generally serve to stabilize tolls -practicality -keep tolls closer to long run MC in expanding system v) incremental favoured on dedicated laterals c) Averch Johnson effect-with guaranteed return on rate base, monopolist has no incentive to control inefficiency & will also tend to over-invest in capital i) regulators only allow prudently incurred costs in rate base ii) regulator requires there is need for expansions iii)regulator determines return on equity iv)given regulator behaviour, more of an issue on operating costs d)regulatory burden i) COS regulation can involve frequent, costly, adversarial rate hearings ii) hearing provides transparent, institutional framework for bargaining iii)regulators have seriously streamlined the process in recent years iv)move towards negotiated settlements between major stakeholders 8. Incentive Regulation a) aim is to improve performance of regulated firm through use of rewards & penalties beyond those incorporated in traditional COS regulation -cost savings ultimately get shared with users of system -results in marginal changes in effective return on equity 9. TCPLAlberta (formerly Nova Gas Transmission Limited (NGTL), NOVA & Alberta Gas TrunkLine (AGTL)) a) established in 1954 by the AB government as AGTL - government noted “the efficient development, gathering & utilization of the gas resources of the province would be promoted by the institution of a trunk line system operating as a common carrier under full provincial jurisdiction & control “ -objectives included i) conservation & efficient utilization of gas resources in province ii) flexibility of development such that, diversion of gas from in province to export, or vice versa, is possible iii)access to consumers in AB to gas which can be delivered most economically iv)control of gas within province by provincial authorities v)joint & efficient use of field, plant, pipeline & other facilities for mutual benefit of consumers, producers & distributors b) as export pipelines were developed, 2 distinct operational sections emerged i) eastern section feeding into TCPL at Empress ii) western section that went to the AB/BC border & transported to Pacific Northwest & California iii)costs attributable to each section were easily distinguished & different distance-based tolling arrangements were developed for each iv)as facilities were put in place for intra-AB market, these were also tolled on a separate basis c)system expanded into the 1970s -facilities on eastern & western sections became physically integrated -tolls become difficult to administer i) common cost allocation issues ii) incremental (vintage) tolling developed; customers could pay different rates for same service d)in 1977, Alberta Public Utilities Board recommended postage stamp (uniform) tolls be adopted for gas leaving the province due to: i) AGTL’s system is fully integrated ii) simplest & most easily understood method, avoids administrative complexity inherent in all other proposed methods iii)encourages gas development in more remote areas iv)choice of boundaries is not arbitrary as with zone method v)facilitates gas exchanges vi) introduced in 1980 for exports vii) same arguments applied for intra-AB system-went to postage stamp in 1989 viii) on average, gas destined for export travelled twice as far as gas headed for intra-AB market so export toll was twice the intra-AB toll e)deregulation and market growth led to major expansions in system between 1988 & 1996 i) gas volumes on system doubled from 1986-96 ii) rate base increased from $1.3 billion to $4.8 billion from 1986-96 iii)constant $ tolls were actually lower in 1996 than in 1986, despite the huge expansions (Figure 13) iv)gas producers were facing very low prices & sought to increase netbacks through lower tolls -claimed that NGTL: -didn’t respond to service requests fast enough -was inflexible in contracting -had no incentive to operate efficiently v) responses included: -shift from long-term (10-15 year) contracts to short-term contracts (1-5 years) -move towards incentive settlements where operating cost reductions were shared by NGTL & shippers f) bypass proposals emerged i) producers with interests concentrated in southern AB thought postage stamp toll was unfair ii) move to short-term contracts allowed shippers to abandon capacity on NGTL iii)AB government likely wouldn’t approve a bypass pipeline, wanted postage stamp iv)solution was to propose pipeline that crossed provincial border-subject to NEB regulation g)Palliser pipeline proposed by PanCanadian et al in 1996/97 i) 1.0 Bcf/d pipeline extending inches into Saskatchewan ii) NGTL postage stamp was 25 cents/mcf iii)Palliser toll would be 17 cents/mcf, but would force NGTL postage stamp up to 27 cents/mcf iv)if Palliser was allowed to proceed, would make bypass deeper into province economic -death spiral for NGTL v) NGTL had looked into zone tolls prior to Palliser application, couldn’t get industry consensus vi) solution-Palliser shippers receive ‘load retention’ rate of 15 cents/mcf; postage stamp rises to 26 cents/mcf for others vii) avoided stranded capacity, but end of postage stamp tolls h)Alliance pipeline proposed in 1997/98 i) 1.6 Bcf/d pipeline extending from NEBC to Chicago ii) bullet line, no Cdn delivery points iii)toll structure which encouraged shipment of NGLs iv)proponents claimed NGTL/TCPL needed competition & extra takeaway capacity was needed from Canada v)fact is all Alliance volumes in AB (1.4 Bcf/d) were already on NGTL/TCPL systems-pure displacement vi) Alliance represented ‘regulatory competition,’ seeking & receiving special treatment from the NEB -15 year contracts vs 1 year contracts on NGTL -11.3% return on equity vs. 9.5% return on other pipelines vii) toll impacts on NGTL -Figures 13/14 -Alliance starts up in late 2000 -TCPLAB & overall AB volumes very close until 2001 -TCPLAB loses 0.5-0.6 Tcf/yr, until tolls rise by 15% -Alliance toll within AB is 35 cents/mcf, TCPLAB toll went to 30 cents/mcf vs. 25-26 without Alliance -additional $200 mm/year in unnecessary transportation costs -Alliance proponents claimed capacity addition brought prices in AB in line with rest of continent WRONG Foothills/Northern Border in 97/98 prices in line; existing systems could have been expanded at much lower cost i)TCPLAB system today -over 900 receipt points, over 200 delivery points -have moved to distance/volume based tolls;
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