Winter U.S. Natural Gas Production and Supply Outlook

Transcription

1 Winter U.S. Natural Gas Production and Supply Outlook Prepared for Natural Gas Supply Association by: ICF International Fairfax, Virginia September, 2012 Introduction This report presents ICF s current view of upstream industry activity, production, storage, and imports for the upcoming winter heating season. Significant developments in North American gas supply since our last report in the fall of 2011 are: Continued increase in U.S. gas production to new record levels; large increase in natural gas liquids production Low wellhead prices and relatively high crude prices; large decline in natural gas liquids prices since early 2012 Decline in reported gas-directed rigs and reduction in gas well completions Increase in reported oil-directed drilling rigs, many of which are targeting wet gas Sharp activity reductions in dry gas portions of shale plays Increased production from Marcellus despite fewer rigs, reflecting large overhang of unconnected wells Large amount of drilling activity in wet gas and tight oil; rapidly increasing oil and associated gas production; growth in Lower-48 onshore oil production Dominance of Bakken and Eagle Ford plays in tight oil activity Increased role of sandstone plays in unconventional production, including the Granite Wash and Permian Basin plays Emerging tight oil and wet gas plays include the Utica, Mississippi Lime, and Tuscaloosa Marine Shale 1

2 Continuing trend toward much longer horizontal laterals with more frac stages; higher well recoveries; improved economics Large scale build-out of midstream infrastructure to handle liquids production Hurricane Isaac resulted in the shutting in of a cumulative 28 Bcf of offshore gas production; no significant impact on markets Summary of Supply Indicators and Gas Production Gas-directed rig activity is down 30 percent and oil-directed activity is up 40 percent Gas well completions are down 33 percent Onshore rig costs are flattening after a period of rapid increase Lower-48 dry gas production in 2012 will be approximately 64.7 Bcf/d, or about 2.1 percent higher than in This is a much lower rate of growth than last year. Shale gas production as defined here (excluding tight oil) increased to 22.4 Bcf/d at year-end 2011, compared with 16.9 Bcf/d at year-end 2010 Working gas in storage at the end of August was 3.40 Tcf vs 3.02 Tcf last year. The forecast fill level for November 1 st is 3.91 Tcf, slightly above last year, and representing 94 percent of capacity. Pipeline imports from Canada will be higher than last year, largely because of the very warm winter last year. LNG imports will be unchanged. Data Sources and Approach The production analysis presented here is based upon analysis of data from commercial data, state agencies, and the Energy Information Administration (EIA). It incorporates a procedure to estimate recent production where reported production is not yet complete due to a reporting lag. Historic gas production at the play level is based upon ICF analysis of state agency and commercial well level production data, as well as company reports. The gas production forecast 2

3 presented here is consistent with the ICF Natural Gas Market Compass forecast, a detailed 25 year forecast and gas market analysis of North America that is developed quarterly. 1 Forecasts of gas storage fill, pipeline imports, and LNG imports are from Compass. For consistency between historic data and forecasts, some of the historic data shown differ slightly from EIA data. Emergence of Lower-48 Shale Plays Exhibit 1 illustrates the emergence of new U.S. shale plays through time. A decade ago, the only plays with drilling activity were the Fort Worth Barnett Shale, the Antrim Shale (Michigan Basin), and the New Albany Shale (Illinois Basin), in addition to minor vertical drilling in the Marcellus. Today, very active horizontal shale gas and tight oil plays are located in many parts of the country, and potential plays are present in most major producing basins. 1 Data area from the July, 2012 ICF Natural Gas Market Compass. 3

4 Exhibit 1 Original and Current Shale Gas and Tight Oil Plays 4

5 Drilling Activity U.S. total oil and gas rig activity (Baker-Hughes) in August 2012 averaged 1,871 rigs, which was 4 percent lower than in August of Sharp declines in gasdirected rig activity have been offset by increasing oil-directed activity, such that total rig activity has been relatively constant. These relationships are shown in Exhibit 2. The steep decline in gas rigs that began in late 2011 continues, but at a diminishing rate. Oil rig activity increased linearly, but in August appeared to begin to level off. Exhibit 2 The issue of classification of drilling rigs as gas rigs or oil rigs is significant for supply analysis. Prior to shale gas activity, there was little uncertainty about whether a rig was drilling for oil or dry gas. However, many shale plays, especially those that have been the most active recently, have a transition from oil to wet gas and dry gas. Currently, many rigs that are classified as oil-directed are drilling in the wet gas (gas and liquids) window of shale plays. Their production is therefore gas with liquids, which is far different from crude oil and 5

6 associated gas production. Because of this, the gas and oil-directed rig statistics can be of limited use in some cases in forecasting near-term oil and gas production trends. Largely dry gas plays such as the Haynesville, Barnett, Fayetteville, Arkoma Woodford and parts of the Marcellus have seen large declines in activity. In some cases, as with the Barnett, activity stabilized in In other cases, dry gas-directed activity continues to decline. Increases in oil-targeted drilling activity are widely distributed. Activity can be broadly divided into tight oil and wet gas. Areas of tight oil emphasis include the Bakken/Three Forks and Eagle Ford, the Permian Basin (Avalon, Bone Springs, Wolfberry, and Cline), and the Denver Niobrara. Numerous tight oil plays are taking off in western Canada as well, including the Cardium and Viking. Tight oil production in the Lower-48 is approximately 1.1 million barrels per day, mostly from the Bakken and Eagle Ford, and tight oil production in Canada is 200,000 barrels per day. 2 Drilling in wet gas plays is concentrated in the Granite Wash, Eagle Ford, Marcellus, and Cana Woodford. The wet gas plays are characterized by high volume gas production with a heavy natural gas liquids component. The increase in oil and wet gas directed rigs has resulted in surging NGL production, creating a glut in some markets and driving down NGL prices. This, combined with low natural gas prices is having an impact on the profitability of some shale gas development. A key factor in the low NGL prices is the transportation bottleneck at Conway, Kansas. The planned expansion of NGL transportation out of Conway by 2014 will improve the situation. 3 Continued development of NGL export markets will also be important. Over 800,000 b/d of propane and butane export terminal expansions have been announced. 2 National Energy Board, Tight Oil Developments in the Western Canada Sedimentary Basin, Dec.,

7 Exhibit 3 presents 2012 trends in total drilling activity by region. There was a national decline in rigs of four percent relative to August Most of the decline was in Louisiana, Appalachia, and other. Texas, the Rockies, and North Dakota saw continued gains. Exhibit 3 U.S. and Canadian Drilling Trends August Data - Total Rigs (Oil and Gas) Source: Baker Hughes Total Rigs Total Rigs Total Rigs Aug Aug Change (%) Regional U.S. Rig Trends Rockies % North Dakota % Midcontinent % Texas % Louisiana % Gulf of Mexico % Appalachia % Other % Lower-48 1,951 1,871-4% 3 7

8 Exhibit 4 compares rig activity in 2011 and Gas rig counts for the first eight months of 2012 averaged 629. This can be compared to an average of 896 gas rigs during the same period last year, a decline of 30 percent. On a calendar year basis, ICF is forecasting an average of 567 gas rigs this year, a decline of 37 percent. For oil-directed rigs, continued gains are expected, with a forecast 40 percent increase for Total rig activity is forecast to increase by 3.5%. Exhibit 4 Historical and Forecast Gas Rigs change January through August gas rigs (actual) % Annual average gas rigs * -36.6% Annual average oil rigs 978 1,372 * 40.3% Annual average total rigs 1,873 1,939 * 3.5% * 2012 forecast 8

9 Drilling Cost Trends Exhibit 5 shows the average day rate for onshore drilling rigs in the U.S. This is a key component of U.S. drilling costs. The average day rate doubled between 2003 and There was a sharp decline through Since then, onshore average day rates have continued to climb. However, rig rates in the second quarter of this year declined, reversing a two year trend. This reflects softness in demand for the specialized rigs used for horizontal shale gas. Exhibit 5 9

10 Exhibit 6 shows approximate rig rates for offshore deepwater semisubmersibles. These day rates more than quadrupled after 2003, peaking in Over the past two years, rates have climbed again to almost that level, reflecting the effects of worldwide strong demand for deepwater rigs. The primary reason deepwater rigs are in high demand around the world is the success achieved in emerging deepwater oil and gas provinces in South America and Africa. Gulf of Mexico deepwater activity has also rebounded. Exhibit 6 10

11 Gas Well Completions Exhibit 7 shows monthly U.S. gas well completion statistics from the EIA Monthly Energy Review. Completion activity in 2012 is much lower, and continues the trend observed in the last quarter of The number of monthly gas completions is impacted by many factors including the gas-directed rig count, geographic and play distribution, average well depths, and well complexity. Note that the recent declines correspond with the gas-directed rig trend. Exhibit 7 11

12 Exhibit 8 presents Lower-48 gas well completion statistics starting with the first quarter of The table presents EIA Monthly Energy Review data, API Quarterly Completion Report data, and ICF estimates. ICF is forecasting the completion of about 9,000 Lower-48 gas wells in This represents a decline of 33 percent from the estimated 13,300 wells completed in The actual count for 2011 was lower than forecast last year (15,300). This was due to lower than anticipated gas rig activity and a trend of fewer gas wells completed per active gas rig. Because of the drilling and completion of much longer laterals, wells are more complex, although much more productive. Exhibit 8 Comparison of Quarterly Lower 48 Completion Counts Estimated Gas Well Completions Sources: EIA Monthly Energy Review and API Completion Report. EIA API Monthly Energy Quarterly Comp. Review Report ICF With Estimated Estimated Forecast 2009 Q1 6,626 5,851 5, Q2 4,135 3,586 3, Q3 4,074 3,666 3, Q4 4,280 3,475 3, Q1 3,831 3,536 3, Q2 3,895 3,546 3, Q3 4,483 3,986 3, Q4 4,487 4,091 4, Q1 3,501 3,379 3, Q2 3,515 3,261 3, Q3 3,371 3,372 3, Q4 2,833 3,322 3, Q1 2,119 2,618 2, Q2 1,340 2,472 2, Q , Q ,850 Annual Totals Annual % chg ,115 16,578 16, % ,696 15,159 15, % ,220 13,334 13, % , % 12

13 Natural Gas Production Gas production from onshore unconventional plays continues to drive Lower-48 gas production higher. Despite the slowdown in gas rig activity and gas well completions, gas production continues to increase because of concentration on play sweet spots, higher production rates per well, the lag between drilling and production of shale wells in some areas, and from increased production of associated gas from tight oil and liquids plays. Exhibits 9a and 9b illustrate gas production trends from a selected onshore shale and tight plays. Included in Exhibit 9a are the Barnett Shale in the Fort Worth Basin, the Eagle Ford Shale in south Texas, the Bossier Tight Sandstone in East Texas, the Fayetteville Shale in Arkansas, the Woodford Shale in Eastern Oklahoma, the Jonah and Pinedale tight gas fields in Southwestern Wyoming, the Piceance Basin tight gas in Colorado, the Haynesville Shale of Northern Louisiana and East Texas, the Marcellus Shale in Appalachia and the Powder River Basin coalbed methane. These plays have experienced an increase in gas production of almost 30 Bcf per day since At year-end 2011, production from these plays accounted for 46 percent of Lower-48 gas production, as shown in Exhibit 9b. 13

14 Exhibit 9a Exhibit 9b 14

15 Exhibit 9c shows shale play production. (Note that Bakken associated gas of about 500 MMcf/d in December, 2011 is excluded here). Through 2008, the Fort Worth Barnett Shale was the dominant play. Since 2009, most of the growth has been in other plays, with the Marcellus, Haynesville, and Fayetteville contributing the most. At year-end 2011, the Marcellus was producing almost 5 Bcf/d and growing rapidly, and the Haynesville was producing 7.7 Bcf/d. Lower- 48 shale gas production was 22.4 Bcf/d at year-end 2011, representing 35 percent of Lower-48 wet gas production. ICF has evaluated production and well data from the Pennsylvania portion of the Marcellus. The analysis indicates that there remain a very large number of drilled but nonproducing wells. Continuing hookup of these wells helps explain why production continues to increase despite the large decline in rigs. Eventually, most of this inventory will be connected. Additional analysis is needed to fully evaluate this issue and its implications for future production. Exhibit 9c 15

16 Exhibit 10 presents Lower-48 tight oil production and associated-dissolved gas production from tight oil. The chart shows that tight oil (crude and condensate) production is approximately 1.1 million barrels per day and associated gas production is 1.5 Bcf/d. (Note that this excludes the gas well production in transition plays such as the Eagle Ford). Tight oil and associated gas production from plays other than the Bakken and Eagle Ford is estimated in this analysis (Permian, Niobrara, and Mississippian Lime). The magnitude of growth in tight oil production is also reflected in total onshore production, which has increased substantially. Exhibit 10 Lower-48 Tight Oil and Gas Production 16

17 Exhibits 11 through 13 present the ICF Lower-48 natural gas production analysis and forecast. Lower-48 gas production in the third quarter of 2012 is expected in this analysis to average 64.8 Bcf per day, up from 63.9 Bcf/d in the third quarter of last year. Historic and forecast production levels are presented graphically in Exhibit 12. The lower portion of Exhibit 11 presents an annual summary and shows the percentage change in Lower-48 production. ICF estimates that 2012 production will average 64.7 Bcf/d (23.7 Tcf), a 2.1 percent increase over This contrasts with an 8.6 percent increase last year. The forecast for 2013 is for an average of 65.8 Bcf/d, a 1.6 percent increase over this year. 17

18 Exhibit 11 ICF Analysis of Lower-48 Quarterly Wellhead Gas Production Dry marketed total gas - Bcf per day Quarterly averages Quarterly Bcf/d Quarterly Bcf per day * Change Pct. Chg Q % 2Q % 3Q % 4Q % Q % 2Q % 3Q % 4Q % Q % 2Q % 3Q % 4Q % Q % 2Q % 3Q % 4Q % Q % 2Q % 3Q % 4Q % Annual averages Annual Annual Bcf/d Annual Production Change Bcf per day Change Pct. Chg. Bcf/Yr. Bcf % 20, % 21,298 1, % 23,134 1, % 23, % 24, * Production excludes approximately 1.0 Bcfd of marketed Alaska gas production and 200 MMcfd of supplemental gas production consisting of coal gas and propane-air. 18

19 Exhibit 12 19

20 Exhibit 13 presents the details of winter monthly natural gas production since November 2010 and the ICF forecast for the upcoming winter. The forecast is for Lower-48 production to average 64.8 Bcf/d this winter through March of This is about 0.1 Bcf/d lower than last year. Exhibit 13 Historical and Forecast Winter Monthly Production November - March Source: ICF Database and Models Bcf Historical Historical ICF Forecast for this winter Bcf Bcf Bcf Nov ,804 Nov ,951 Nov ,950 Dec ,866 Dec ,014 Dec ,020 Jan ,910 Jan ,005 Jan ,022 Feb ,715 Feb ,877 Feb ,826 Mar ,920 Mar ,959 Mar ,025 total 9,217 9,806 9,843 Bcf per day Historical Historical ICF Forecast for this winter Bcfd Bcfd Bcfd Nov Nov Nov Dec Dec Dec Jan Jan Jan Feb Feb Feb Mar Mar Mar average

21 Comparison with EIA Short-Term Forecast EIA publishes a short-term forecast each month with quarterly estimates of U.S. natural gas production and imports. Exhibit 14 presents the EIA and ICF quarterly production averages for the Lower-48. EIA is forecasting a 2012 Lower-48 gas production increase of 3.9 percent. This compares to an increase of 2.1 percent in the ICF analysis. The EIA forecast for 2013 is for a 0.7 percent increase, compared with our 1.6 percent increase. 21

22 10-1Q 10-2Q 10-3Q 10-4Q 11-1Q 11-2Q 11-3Q 11-4Q 12-1Q 12-2Q 12-3Q 12-4Q 13-1Q 13-2Q 13-3Q 13-4Q Bcf per Day Exhibit 14 Comparison with EIA Short Term Outlook Bcf per day; Lower-48 and U.S. Total Dry Gas Production ICF Current Study vs. EIA Short Term Outlook Lower 48 ICF EIA EIA Difference (Lower 48) (U.S. Total) (Lower 48) ICF vs.eia Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q % chg. % chg. Difference % % % % % % % % Lower-48 Production Comparison with EIA Short Term Outlook EIA ICF Current Study 52.0 Year and Quarter 22

23 Storage Injection At the end of August 2012, U.S. inventories of working natural gas in storage stood at 3.40 Tcf, or 320 Bcf above the five-year average of 3.08 Tcf and 380 Bcf above the 3.02 Tcf at the end of August, As shown in Exhibit 15a, storage volumes were far above the five year average during most of The excess over the five year average has declined consistently over the past six months. The ICF forecast is for the storage level on November 1 to be approximately 3.91 Tcf. This is about 100 Bcf above last year. Exhibit 15b presents the monthly working gas storage data. EIA recently published a new estimate of storage capacity. 4 EIA estimates that demonstrated peak working gas capacity rose from 4.10 Tcf in April, 2011 to 4.24 Tcf in April, ICF currently estimates that U.S. working gas storage capacity is 4.17 Tcf. This estimate is based upon project level analysis, including estimates for expected startups this year. The method used involves evaluation of historical storage fill in older facilities combined with design capacity for facilities without a history of storage. This estimate is generally equivalent in definition to the EIA demonstrated capacity estimate above. The current ICF forecast of peak storage this fall of 3.91Tcf represents 94 percent of our estimate of storage capacity

24 Exhibit 15a Exhibit 15b Underground Natural Gas Storage - BCF Working Gas - End of Month 2012 With ICF Forecast 2013 Forecast 5 year avg. Jan 2,304 2,308 2,916 2,603 2,238 Feb 1,683 1,724 2,455 2,171 1,656 Mar 1,652 1,581 2,477 2,063 1,552 Apr 2,011 1,789 2,613 2,220 1,772 May 2,420 2,188 2,890 2,585 2,199 Jun 2,740 2,530 3,118 2,557 Jul 2,966 2,774 3,231 2,848 Aug 3,153 3,020 3,402 3,083 Sep 3,508 3,416 3,723 3,409 Oct 3,851 3,804 3,906 3,685 Nov 3,769 3,843 3,781 3,647 Dec 3,111 3,462 3,281 3,085 24

25 Pipeline Imports and Exports Exhibit 16 shows the winter pipeline imports from Canada and exports to Mexico, starting with the winter of Import data are net to the U.S. The historical Canadian import data are taken from the ICF Natural Gas Market Compass. Net imports from Canada last winter ( ) averaged 4.50 Bcf/d, which was about 31 percent lower than the previous winter s average. Last winter s pipeline import volumes were low in part because it was one of the warmest winters on record. This winter we forecast that imports from Canada will average 5.53 Bcf/d, an increase of 23 percent or 1.03 Bcf/d relative to last winter. The volume of Canadian pipeline imports depends on WCSB gas production and demand in both Canada and the U.S. Western Canada production has been declining. Also, gas demand in Alberta has increased, primarily due to oil sands production and processing needs. Exports to Mexico in recent years have been constant at about 1.2 Bcf/d. In the future, Mexico may import larger volumes of natural gas from the U.S. While Mexico has excellent shale gas potential in the Burgos Basin adjacent to Texas, development drilling and significant new production from the basin has not yet occurred. 25

26 Exhibit 16 Pipeline Imports from Canada and Exports to Mexico November though March Sources: ICF Compass for forecast; history from Natural Gas Monthly Net Imports from Canada Bcf per day positive = net imports Historical Historical ICF Forecast for this winter Bcf/d Bcf/d Bcf/d Nov Nov Nov Dec Dec Dec Jan Jan Jan Feb Feb Feb Mar Mar Mar average Net Exports to Mexico Bcf per day negative = net exports Historical Historical ICF Forecast for this winter Bcf/d Bcf/d Bcf/d Nov Nov Nov Dec Dec Dec Jan Jan Jan Feb Feb Feb Mar Mar Mar average Winter LNG Imports In past years, the U.S. typically imported 1.0 to 1.5 Bcf/d of LNG during the winter months. We have historically imported more LNG in the summer months when there is less demand in Europe and Asia. Prior to the boom in shale gas, most analysts believed that LNG imports to the U.S. would ramp up greatly in coming years to fill a supply gap. While LNG is still expected to be a major source of incremental world supply over the long term, it is not expected to contribute greatly in the U.S. for many years due to surging U.S. gas production. There have also been applications to export LNG from Western Canada, the Gulf Coast, and the Atlantic Coast. 5 DOE has approved 26.6 Bcf/d of export

27 application volumes. However, the government has yet to decide the level of LNG exports that will ultimately be allowed. Exhibit 17 shows the recent history of worldwide LNG shipments and world gas production. LNG imports to North America (primarily to the U.S.) declined from 761 Bcf in 2010 to 671 Bcf in U.S. imports (not shown) declined from 432 Bcf in 2010 to 354 Bcf in World production of LNG increased to 11,681 Bcf and world gas production increased from 112 Tcf to 116 Tcf. LNG shipments to Europe, Asia, and South America increased. 27

28 Exhibit 17 World LNG Imports and Gas Production EIA data through 2005; BP Statistical Review for 2006 forward LNG Imports Gas Production LNG World North Post-2000 Gas Post-2000 America Europe Asia - Pacific Other Total Increase Production Increase Bcf Bcf Bcf Bcf Bcf Bcf Tcf Tcf ,150 3,544 4, ,157 3,776 5, ,386 3,671 5, ,390 3,978 5, ,423 4,347 6,453 1, ,668 4,495 6,827 1, ,028 4,774 7,454 2, ,883 5,225 7,994 3, ,949 5,502 7,975 3, ,437 5, ,571 3, ,099 6, ,509 5, ,201 7, ,681 6, Percentage of world LNG imports % 23.3% 71.8% 0.0% 100.0% % 22.3% 72.7% 0.0% 100.0% % 26.1% 69.1% 0.0% 100.0% % 23.5% 67.3% 0.0% 100.0% % 22.1% 67.4% 0.0% 100.0% % 24.4% 65.8% 0.0% 100.0% % 27.2% 64.0% 0.0% 100.0% % 23.6% 65.4% 0.0% 100.0% % 24.4% 69.0% 0.0% 100.0% % 28.4% 62.7% 1.2% 100.0% % 29.5% 59.7% 3.5% 100.0% % 27.4% 62.6% 4.2% 100.0% 28

29 Exhibit 18 shows monthly LNG gross imports for the past two winters and the ICF forecast for this winter. The winter total volume imported for was 200 Bcf, or 1.32 Bcf/d. Last winter, the volume was 112 Bcf, or 0.74 Bcf/d. For the upcoming winter, ICF is forecasting an identical volume of 112 Bcf. Exhibit 18 Historical and Forecast Winter LNG Imports November - March; Gross Imports - Not Net of Alaska Exports Source of historical data: EIA Natural Gas Monthly and ICF Source of forecast: ICF Compass Bcf Historical Historical ICF Forecast for this winter Bcf Bcf Bcf Nov Nov Nov Dec Dec Dec Jan Jan Jan Feb Feb Feb Mar Mar Mar total Bcf per day Historical Historical ICF Forecast for this winter Bcf/d Bcf/d Bcf/d Nov Nov Nov Dec Dec Dec Jan Jan Jan Feb Feb Feb Mar Mar Mar average

30 Percent Change Summary Exhibit 19 summarizes the results of the supply analysis and forecast. Supply Outlook for Winter percent source change change U.S. production vs previous year (trend) Even Annual gas well completions (2011 to 2012) 2 13,334 8,990-4, % Annual gas rig count (2011 to 2012) % Winter LNG imports (Bcf/d - Nov. - March) % Winter average gas production (Bcf/d - Lower 48) % Working gas in storage (Tcf - Nov.1) % Net pipeline imports from Canada (Bcf/d - Nov. - Mar.) % 30% 20% 10% 22.9% Gas Well Completions Gas Rig Count 0% -10% 0-0.2% 2.9% Winter LNG Imports Winter Gas Production -20% Working Gas in Storage -30% Net Pipeline Imports -32.6% -40% -36.6% Sources: 1. ICF - Current Study - State and federal data with ICF adjustments and forecast. 2. API Quarterly Completion Report with ICF estimates. 3. Baker Hughes gas rigs with ICF forecast through December. 4. Historical data from EIA Natural Gas Monthly; Forecast from ICF Compass. 5. Historical and forecast from current study. Derived from state and federal data with adjustments and forecast 6. Historical data from EIA; Forecast from ICF Compass 7. Historical data from StatsCanada and bulletin boards; Forecast from ICF Compass 30