natr s gas daily - platts

Monday, July 11, 2016

GAS DAILY

NATURAL GASwww.platts.com www.twitter.com/PlattsGas

(continued on page 2)

News HeadliNes

Minor leak shuts down California storage field�� Well tests ordered despite low methane release�� Shut-down takes PG&E’s largest field offline


June flows offer insight into Vector’s future�� Eastern Canada relying less on Vector imports �� Vector may see Ontario, Quebec market share decline


Higher ethane demand lessens rejection: eia�� Bump in ethane prices traced to uptick in demand�� Morgan’s Point exports seen to further up demand


Futures up slightly, cash mostly lower THE MARKET The NYMEX August natural gas futures contract climbed 2.4 cents Friday to settle at $2.801/MMBtu.

“The market is in a wait-and-see mode for more summer heat and increased demand as it has not yet been as hot as expected,” said Tradition Energy analyst Mariana Eizayaga.

iNside tHis issue

($/MMBtu)

SPOT PRICE AND BASIS CHANGES

-0.8

-0.4

0.0

0.4

0.8

TX E

aste

rn M

-3 (N

E)

Dom

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n S

Pt (

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Chi

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(Mid

C)

Hen

ry H

ub (S

E)

Hou

ston

Shi

p (E

TX)

Wah

a (S

W)

Panh

andl

e TX

-OK

(Mid

C)

CIG

(NW

)

PG&

E C

G (S

W)

SoC

al G

as (S

W)

Sum

as (N

W)

AEC

O-C

(NW

)

Source: Platts

Daily spot price changeDaily cash basis changeDaily spot price change from bidweek

daily priCe surVey ($/MMBtu)NATIONAL AVERAGE PRICE: 2.500Trans. date: 7/08Flow date(s): 7/09 —11

Midpoint +/- absolute Common Vol. deals

Northeast

Algonquin, city-gates IGBEE21 2.070 -0.990 2.000-2.200 2.020-2.120 166 25

Algonquin, receipts IGBDK21 — — ——- ——- — —

Dracut, Mass. IGBDW21 — — ——- ——- — —

Iroquois, receipts IGBCR21 2.600 -0.290 2.520-2.700 2.555-2.645 108 29

Iroquois, zone 2 IGBEJ21 2.580 -0.390 2.540-2.620 2.560-2.600 90 20

Niagara IGBCS21 — — ——- ——- — —

Tennessee, z6 (300 leg) del. IGBJC21 — — ——- ——- — —

Tennessee, zone 6 del. IGBEI21 2.030 -1.070 1.850-2.200 1.945-2.120 219 32

Tx. Eastern, M-3 IGBEK21 1.435 -0.155 1.400-1.500 1.410-1.460 198 38

Transco, zone 5 del. IGBEN21 2.720 -0.165 2.050-2.830 2.525-2.830 227 33

Transco, zone 5 del. North IGCGL21 2.340 -0.495 2.050-2.500 2.230-2.455 47 11

Transco, zone 5 del. South IGCHL21 2.815 -0.080 2.800-2.830 2.810-2.825 181 22

Transco, zone 6 N.Y. IGBEM21 1.650 -1.270 1.600-1.800 1.600-1.700 65 16

Transco, zone 6 non-N.Y. IGBEL21 1.675 -1.175 1.600-1.750 1.640-1.715 223 42

Transco, zone 6 non-N.Y. North IGBJS21 1.675 -1.175 1.600-1.750 1.640-1.715 223 42

Transco, zone 6-non-N.Y. South IGBJT21 — — ——- ——- — —

Northeast regional average IGCAA21 2.095

appalachia

Columbia Gas, App. IGBDE21 2.680 -0.100 2.635-2.700 2.665-2.695 166 41

Columbia Gas, App. non-IPP IGBJU21 — — ——- ——- — —

Dominion, North Point IGBDB21 1.370 -0.115 1.300-1.395 1.345-1.395 58 15

Dominion, South Point IGBDC21 1.380 -0.125 1.300-1.410 1.355-1.410 531 88

Lebanon Hub IGBFJ21 2.630 -0.100 2.600-2.660 2.615-2.645 102 13

Leidy Hub IGBDD21 — — ——- ——- — —

Millennium, East receipts IGBIW21 1.350 -0.135 1.320-1.360 1.340-1.360 30 7

REX, Clarington Ohio IGBGO21 — — ——- ——- — —

Tennessee, zone 4-200 leg IGBJN21 1.590 -0.040 1.550-1.700 1.555-1.630 181 19

Tennessee, zone 4-300 leg IGBFL21 1.315 -0.050 1.285-1.390 1.290-1.340 44 8

Tennessee, zone 4-313 pool IGCFL21 1.570 -0.015 1.540-1.650 1.545-1.600 90 17

Tennessee, zone 4-Ohio IGBHO21 — — ——- ——- — —

Texas Eastern, M-2 receipts IGBJE21 1.325 -0.155 1.295-1.365 1.310-1.345 214 49

Transco, Leidy Line receipts IGBIS21 1.405 -0.120 1.360-1.430 1.390-1.425 113 20

Appalachia regional average IGDAA21 1.660

Midcontinent

ANR, Okla. IGBBY21 2.495 -0.095 2.480-2.505 2.490-2.500 60 13

Enable Gas, East IGBCA21 2.575 -0.135 2.530-2.600 2.560-2.595 189 14

NGPL, Amarillo receipt IGBDR21 2.560 -0.065 2.500-2.580 2.540-2.580 51 9

NGPL, Midcontinent IGBBZ21 2.545 -0.030 2.480-2.570 2.525-2.570 303 46

Oneok, Okla. IGBCD21 2.505 -0.025 2.420-2.520 2.480-2.520 41 10

Panhandle, Tx.-Okla. IGBCE21 2.505 -0.025 2.460-2.560 2.480-2.530 475 73

Southern Star IGBCF21 2.510 -0.020 2.485-2.530 2.500-2.520 82 16

Tx. Eastern, M-1 24-in. IGBET21 2.660 -0.040 2.660-2.660 2.660-2.660 5 1

Midcontinent regional average IGEAA21 2.545

upper Midwest

Alliance, into interstates IGBDP21 2.635 -0.100 2.600-2.665 2.620-2.650 182 34

ANR, ML 7 IGBDQ21 2.635 -0.195 2.600-2.680 2.615-2.655 34 3

Chicago city-gates IGBDX21 2.655 -0.130 2.615-2.695 2.635-2.675 433 57

Chicago-Nicor IGBEX21 2.655 -0.130 2.630-2.695 2.640-2.670 128 19

Chicago-NIPSCO IGBFX21 2.660 -0.125 2.640-2.690 2.650-2.675 250 29

Chicago-Peoples IGBGX21 2.650 -0.130 2.635-2.665 2.645-2.660 43 5

Consumers city-gate IGBDY21 2.685 -0.100 2.630-2.705 2.665-2.705 117 19

Dawn, Ontario IGBCX21 2.710 -0.080 2.680-2.770 2.690-2.735 854 112

Emerson, Viking GL IGBCW21 2.460 -0.095 2.380-2.480 2.435-2.480 137 30

Mich Con city-gate IGBDZ21 2.645 -0.125 2.615-2.685 2.630-2.665 243 42

Northern Bdr., Ventura TP IGBGH21 2.575 -0.110 2.480-2.650 2.535-2.620 103 14

Northern, demarc IGBDV21 2.575 -0.110 2.520-2.615 2.550-2.600 122 29

Northern, Ventura IGBDU21 2.575 -0.115 2.500-2.615 2.545-2.605 95 16

REX, Zone 3 delivered IGBRO21 2.640 -0.105 2.605-2.655 2.630-2.655 617 78

Upper Midwest regional average IGFAA21 2.615

Panda gas plants begin service in Pennsylvania 8INGAA offers alternatives to PHMSA safety rule 8US LNG exports driving break from oil-linkage 9Court decisions uphold FERC LNG review 10Gas Daily Supplement Links 13

2

Monday, July 11, 2016Gas daily

© 2016 s&P Global Platts, a division of s&P Global. all rights reserved.

Daily price survey ($/MMBtu)Trans. date: 7/08Flow date(s): 7/09 —11

Midpoint +/- absolute common vol. Deals

assessMeNt ratioNalePlatts Gas Daily indices are based upon trade data reported to Platts by market participants. The indices are calculated using detailed transaction level data from these providers. Platts editors screen the data for outliers that may be further examined and potentially removed. A volume weighted average is then calculated from the remaining set of data. For more details on this methodology please see our North American Natural Gas Methodology and Specifications Guide on Platts.com, located at http://www.platts.com/IM.Platts.Content/MethodologyReferences/MethodologySpecs/na_gas_methodology.pdf

Questions may be directed to Curt Mrowiec at 713-658-3271 or [email protected].

east texas

Agua Dulce Hub IGBAV21 — — ——- ——- — —

Carthage Hub IGBAF21 2.700 -0.080 2.695-2.700 2.700-2.700 65 9

Florida Gas, zone 1 IGBAW21 2.715 -0.075 2.685-2.720 2.705-2.720 93 8

Houston Ship Channel IGBAP21 2.680 -0.070 2.670-2.700 2.675-2.690 70 6

Katy IGBAQ21 2.695 -0.055 2.670-2.710 2.685-2.705 593 33

NGPL, STX IGBAZ21 2.640 -0.115 2.640-2.645 2.640-2.640 33 4

NGPL, Texok zone IGBAL21 2.645 -0.070 2.635-2.680 2.635-2.655 227 29

Tennessee, zone 0 IGBBA21 2.590 -0.110 2.580-2.605 2.585-2.595 86 22

Tx. Eastern, ETX IGBAN21 2.675 -0.040 2.650-2.700 2.665-2.690 7 5

Tx. Eastern, STX IGBBB21 2.705 -0.080 2.680-2.720 2.695-2.715 99 14

Transco, zone 1 IGBBC21 2.690 -0.095 2.690-2.690 2.690-2.690 10 2

Transco, zone 2 IGBBU21 2.680 -0.090 2.680-2.680 2.680-2.680 15 1

East Texas regional average IGGAA21 2.675

louisiana/southeast

ANR, La. IGBBF21 2.690 -0.080 2.670-2.780 2.670-2.720 108 14

Columbia Gulf, La. IGBBG21 2.715 -0.075 2.710-2.730 2.710-2.720 95 17

Columbia Gulf, mainline IGBBH21 2.680 -0.075 2.670-2.690 2.675-2.685 412 49

Florida city-gates IGBED21 6.490 -0.350 5.000-6.900 6.015-6.900 63 7

Florida Gas, zone 2 IGBBJ21 2.760 -0.100 2.750-2.760 2.760-2.760 97 7

Florida Gas, zone 3 IGBBK21 2.900 -0.030 2.790-2.950 2.860-2.940 320 29

Henry Hub IGBBL21 2.770 -0.080 2.755-2.820 2.755-2.785 162 32

Southern Natural, La. IGBBO21 2.730 -0.070 2.720-2.770 2.720-2.745 451 64

Tennessee, 500 Leg IGBBP21 2.725 -0.065 2.700-2.760 2.710-2.740 144 18

Tennessee, 800 Leg IGBBQ21 2.685 -0.075 2.685-2.700 2.685-2.690 185 30

Tx. Eastern, ELA IGBBS21 2.695 -0.050 2.690-2.700 2.695-2.700 8 3

Tx. Eastern, M-1 30-in. IGBDI21 2.700 -0.055 2.695-2.700 2.700-2.700 9 2

Tx. Eastern, WLA IGBBR21 2.690 -0.075 2.690-2.730 2.690-2.700 138 10

Tx. Gas, zone 1 IGBAO21 2.665 -0.070 2.645-2.685 2.655-2.675 201 21

Tx. Gas, zone SL IGBBT21 2.670 -0.080 2.650-2.670 2.665-2.670 7 2

Transco, zone 3 IGBBV21 2.715 -0.080 2.710-2.720 2.715-2.720 118 12

Transco, zone 4 IGBDJ21 2.740 -0.070 2.725-2.770 2.730-2.750 653 102

Trunkline, ELA IGBBX21 2.620 -0.100 2.610-2.650 2.610-2.630 12 7

Trunkline, WLA IGBBW21 — — ——- ——- — —

Trunkline, zone 1A IGBGF21 2.655 -0.015 2.630-2.660 2.650-2.660 34 8

Louisian/Southeast regional average IGHAA21 2.910

rockies/Northwest

Cheyenne Hub IGBCO21 2.475 +0.000 2.470-2.490 2.470-2.480 65 15

CIG, Rockies IGBCK21 2.465 -0.010 2.450-2.480 2.460-2.475 17 6

GTN, Kingsgate IGBCY21 2.280 +0.075 2.220-2.300 2.260-2.300 100 16

Kern River, Opal IGBCL21 2.505 +0.035 2.450-2.530 2.485-2.525 329 50

NW, Can. bdr. (Sumas) IGBCT21 2.310 +0.100 2.270-2.350 2.290-2.330 277 46

NW, s. of Green River IGBCQ21 2.455 +0.015 2.455-2.455 2.455-2.455 9 5

NW, Wyo. Pool IGBCP21 2.480 +0.040 2.450-2.510 2.465-2.495 38 8

PG&E, Malin IGBDO21 2.545 +0.055 2.515-2.560 2.535-2.555 252 34

Questar, Rockies IGBCN21 2.460 -0.010 2.450-2.475 2.455-2.465 17 4

Stanfield, Ore. IGBCM21 2.410 +0.045 2.380-2.420 2.400-2.420 153 23

TCPL Alberta, AECO-C* IGBCU21 2.180 -0.055 2.115-2.245 2.150-2.215 1219 135

Westcoast, station 2* IGBCZ21 1.085 -0.985 0.900-1.900 0.900-1.335 149 36

White River Hub IGBGL21 2.490 +0.005 2.480-2.505 2.485-2.495 94 10

Rockies/Northwest regional average IGIAA21 2.445

southwest

El Paso, Bondad IGBCG21 2.490 -0.015 2.475-2.500 2.485-2.495 42 7

El Paso, Permian IGBAB21 2.510 -0.015 2.490-2.530 2.500-2.520 311 48

El Paso, San Juan IGBCH21 2.500 -0.005 2.480-2.520 2.490-2.510 171 28

El Paso, South Mainline IGBFR21 2.620 -0.005 2.600-2.670 2.605-2.640 258 29

Kern River, delivered IGBES21 2.580 +0.005 2.530-2.615 2.560-2.600 117 19

PG&E city-gate IGBEB21 2.685 -0.010 2.670-2.725 2.670-2.700 375 49

PG&E, South IGBDM21 2.575 +0.005 2.540-2.600 2.560-2.590 39 8

SoCal Gas IGBDL21 2.610 +0.035 2.590-2.620 2.605-2.620 166 17

SoCal Gas, city-gate IGBGG21 2.630 +0.035 2.600-2.650 2.620-2.645 253 41

Transwestern, Permian IGBAE21 2.510 -0.050 2.480-2.520 2.500-2.520 72 9

Transwestern, San Juan IGBGK21 2.495 -0.015 2.475-2.500 2.490-2.500 68 16

Waha IGBAD21 2.570 -0.050 2.500-2.630 2.540-2.605 336 41

Southwest regional average IGJAA21 2.565

*Price in C$ per gj; C$1=US$0.7649; Volume in 000 MMBtu/day. Symbols represent gas flow date.

4�DAY�AHEAD TEMPERATURE FORECAST MAP

Source: Platts, Custom Weather

The August contract tumbled about 22 cents Tuesday and has since been inching back towards its pre-slump price. The front-month futures contract has cooled off after rallying more than 60 cents in June.

“We may see sideways trading for a while before moving higher on late summer heat,” Eizayaga said.

The US National Weather Service’s latest eight- to 14-day forecast calls for a high probability of above-normal temperatures across the eastern half of the US. The Southwest and Pacific Northwest can expect cooler-than-normal temperatures.

The August contract traded in a range between $2.748/MMBtu and $2.825/MMBtu on Friday.

US power burn was expected to drop 1.9 Bcf Friday after Thursday saw a new year-to-date high of 36.7 Bcf, according to S&P Global Platts unit Bentek Energy.

Supply and demand is expected to be out of balance, with total supply including imports at about 77 Bcf/d and total demand at nearly 71 Bcf/d, over the next seven days, according to Bentek data.

The US Energy Information Administration on Thursday reported that gas in storage increased 39 Bcf to 3.179 Tcf in the week that

http://www.platts.com/IM.Platts.Content/MethodologyReferences/MethodologySpecs/na_gas_methodology.pdf

http://www.platts.com/IM.Platts.Content/MethodologyReferences/MethodologySpecs/na_gas_methodology.pdf

3



total Net pipeliNe Flows By regioN (MMcf/d*) 07-Jul 08-Jul Change Mtd Mtd Change avg. last year

supply regions – net pipeline outflows

Texas 8,528 8,229 299 7,943 9,861 -1,918West Canada 9,047 8,683 364 8,890 8,777 113Rockies 6,578 6,639 -61 6,508 7,115 -607Midcontinent 2,240 2,152 88 2,138 3,414 -1,276Northeast 2,179 3,082 -903 3,130 1,908 1,222

demand regions – net pipeline inflows

Southwest 4,206 4,192 -14 4,577 5,769 1,192Southeast 7,275 7,425 150 6,726 5,957 -769Northwest 1,433 1,203 -230 1,378 1,486 108Midwest 9,760 9,775 15 9,286 11,453 2,167East Canada 2,221 2,597 376 2,974 3,202 228

* Net pipeline flows by region are the aggregated total interstate pipeline flows across the regional bor-der. Net supply regions are those that historically have had more supply than demand within the region and have been net suppliers of gas to other regions. Net demand regions historically have had more demand than supply and have been net receivers of pipeline gas from other regions.

pipeliNe MaiNteNaNCe

start date end date pipeline description

01-May 31-Aug Algonquin Algonquin will be conducting maintenance on the mainline compressor station Stony Point in Rockland County, NY from 5/1 to 8/31 that will restrict capacity by 615 MMcf/d.

01-Jun 31-Aug Algonquin Algonquin will be conducting maintenance on the mainline compressor station Stony Point in Rockland County, NY from 5/1 to 8/31 that will restrict capacity by 615 MMcf/d.

29-Jun 31-Aug Algonquin Capacity through Stony Point compressor will be reduced by approx. 600 MMcf/d, from a design of 1.5 Bcf/d to 886 MMcf/d, due to ongoing maintenance related to the AIM Expansion Project

01-Jul 07-Jul PG&E PG&E has extended maintenance work at the Burney compressor station on the Redwood Path through July 7, restricting capacity by 86% to 1,810 MMcf/d.

19-Jul 25-Jul REX Zone 3 Capacity Enhancement construction will take segment between ANR-Shelby and TCO-Fairfield out of service

19-Jul 22-Jul REX REX to shut-in Seneca receipt point for maintenance

21-Jul 21-Jul REX REX pig run between Blue Mound and Bainbridge

18-Jul 31-Jul Tennessee Tennessee Gas Pipeline will be conducting a maintenance on 7/18 through 7/31 at station 110, that will impact southbound throughput on segment 187 BH (south through KY).

13-Jun 16-Jul Texas Gas Texas Gas will be performing maintenance work on the Lebanon-Dillsboro segment from June 13 to July 16.

06-Jul 13-Jul Transco Transco Leidy Line maintenance to reduce capacity by 470 MMcf/d

ended July 1, below the consensus expectations of analysts surveyed by Platts, who were expecting a 42-Bcf build.

The storage build was below both the 83-Bcf injection reported for the same week in 2015 as well as the 77-Bcf five-year average injection, according to EIA data.

Northeast spot tumbles on mild weatherThe biggest decline came from Transcontinental Gas Pipe Line

Zone 6 New York, which dropped by nearly $1.30/MMBtu.The fall in prices came as the New York City area temperatures fall

to the upper-70s on Saturday, a more than 10-degree decline from Friday’s high.

As milder weather moves into the region, total Northeast demand is expected to fall sharply over the weekend, averaging around 13.8 Bcf/d over the next three days, down nearly 1.4 Bcf/d from Friday’s level.

Looking ahead to next week, demand is expected to pick up after the weekend, returning to levels of about 14 Bcf/d as early as next Tuesday and reaching above 15 Bcf/d by the end of the week, likely

putting pressure back on spot prices.Toward New England markets, Tennessee Gas Pipe Line Zone 6

200 Line dropped almost $1.10.TGP notified shippers Friday morning that it was lifting the

imbalance warning that had been in place since Tuesday.Elsewhere in the region, Algonquin Gas Transmission city-gates

prices were also down sharply, falling nearly $1.00.According to an AGT notice Friday, the pipeline is lifting the

operational flow order on its system that was issued on July 6.At benchmark Henry Hub, spot prices fell 8 cents.The fall in prices came as Bentek forecast Southeast demand

to fall to an average of around 18.5 Bcf/d over the next three days, down more than 200 MMcf/d from Friday’s level. The fall in demand was primarily driven by a reduction in demand for power generation.

demand weighs on Midwest cashAfter the past few days of warm weather, temperatures in the

Detroit and Chicago market areas are expected to return to their seasonal averages during the weekend.

Chicago city-gates prices saw some of the steepest declines, dropping about 13 cents. Farther west in Detroit, Michcon city gates fell roughly 12 cents.

Meanwhile, spot prices in the Midcontinent also fell on projections of reduced outflows and cooler weekend temperatures.

Bentek expects that the market area’s almost week-long trend of increasing outflows may finally be coming to an end on Friday, declining by some 70 MMcf/d from Thursday. This decrease in outflows can be attributed to expectations of cooler weekend temperatures in Detroit and Chicago.

Additionally, cooler weather in the producing region itself helps explain the market area’s declining demand, which is some 30 MMcf/d below the prior seven-day average. Indeed, demand from power burn is expected to fall slightly, Bentek reports. This should leave Friday’s Midcontinent demand at about 2.6Bcf/d.

4



weekly weigHted aVerage priCes 07/02-07/08 wkly total 2016 -/+ High low Volumes

Northeast

Algonquin, city-gates IGBEE04 2.760 0.020 2.871 2.636 794

Algonquin, receipts IGBDK04 1.595 -0.215 1.595 1.595 26

Dracut, Mass. IGBDW04 — — — — 0

Iroquois, receipts IGBCR04 2.751 -0.003 2.864 2.689 1217

Iroquois, zone 2 IGBEJ04 2.808 0.023 2.879 2.729 603

Niagara IGBCS04 — — — — 0

Tennessee, z6 (300 leg) del. IGBJC04 — — — — 0

Tennessee, zone 6 delivered IGBEI04 2.719 -0.004 2.907 2.593 1569

Texas Eastern, M-3 IGBEK04 1.541 -0.286 1.620 1.471 1664

Transco, zone 5 delivered IGBEN04 2.766 0.040 2.894 2.129 1296

Transco, zone 5 del. North IGCGL04 2.236 -0.173 2.292 2.129 311

Transco, zone 5 del. South IGCHL04 2.869 0.040 2.894 2.837 985

Transco, zone 6 N.Y. IGBEM04 2.103 0.074 2.185 1.995 1102

Transco, zone 6 non-N.Y. IGBEL04 2.104 0.024 2.174 2.019 848

Transco, zone 6 non-N.Y. North IGBJS04 2.104 0.095 2.174 2.019 838

Transco, zone 6 non-N.Y. South IGBJT04 2.550 0.159 2.550 2.550 10

appalachia

Columbia Gas, Appalachia IGBDE04 2.763 0.053 2.821 2.731 1160

Columbia Gas, Appalachia non-IPP IGBJU04 1.846 -0.056 1.896 1.367 434

Dominion, North Point IGBDB04 1.461 -0.288 1.500 1.433 320

Dominion, South Point IGBDC04 1.468 -0.292 1.552 1.420 3080

Lebanon Hub IGBFJ04 2.690 0.004 2.709 2.679 464

Leidy Hub IGBDD04 — — — — 0

Millennium, East receipts IGBIS04 1.469 -0.273 1.489 1.460 234

REX, Clarington Ohio IGBGO04 — — — — 0

Tennessee, zone 4-200 leg IGBJN04 1.584 -0.314 1.610 1.544 1383

Tennessee, zone 4-300 leg IGBFL04 1.413 -0.228 1.425 1.400 163

Tennessee, zone 4-313 pool IGCFL04 1.575 -0.251 1.616 1.529 468

Tennessee, zone 4-Ohio IGBHO04 — — — — 0

Texas Eastern, M-2 receipts IGBJE04 1.435 -0.299 1.501 1.381 1514

Transco, Leidy Line receipts IGBIW04 1.474 -0.221 1.549 1.416 819

Midcontinent

ANR, Okla. IGBBY04 2.579 -0.021 2.593 2.561 323

Enable Gas, East IGBCA04 2.672 -0.001 2.690 2.654 715

NGPL, Amarillo receipt IGBDR04 2.609 -0.003 2.618 2.595 123

NGPL, Midcontinent IGBBZ04 2.599 -0.027 2.672 2.566 1862

Oneok, Okla. IGBCD04 2.571 0.000 2.608 2.521 465

Panhandle, Tx.-Okla. IGBCE04 2.571 -0.017 2.625 2.529 2191

Southern Star, Tx.-Okla.-Kan. IGBCF04 2.527 -0.067 2.571 2.499 911

Texas Eastern M-1 24-inch IGBET04 2.764 0.049 2.764 2.764 25

upper Midwest

Alliance, into interstates IGBDP04 2.719 0.030 2.746 2.687 1649

ANR, ML 7 IGBDQ04 2.712 0.056 2.723 2.702 179

Chicago city-gates IGBDX04 2.734 0.027 2.769 2.677 3533

Chicago-Nicor IGBEX04 2.730 0.022 2.760 2.689 1235

Chicago-NIPSCO IGBFX04 2.735 0.028 2.768 2.701 1813

Chicago-Peoples IGBGX04 2.733 0.026 2.762 2.712 292

Consumers Energy city-gate IGBDY04 2.749 0.025 2.765 2.726 1174

Dawn, Ontario IGBCX04 2.774 0.045 2.833 2.736 5238

Emerson, Viking GL IGBCW04 2.503 0.021 2.553 2.454 1124

Mich Con city-gate IGBDZ04 2.730 0.015 2.754 2.709 1876

Northern Border, Ventura TP IGBGH04 2.636 -0.002 2.654 2.606 653

Northern, demarc IGBDV04 2.628 -0.013 2.651 2.598 1151

Northern, Ventura IGBDU04 2.631 -0.008 2.665 2.598 1343

REX, Zone 3 delivered IGBRO04 2.694 0.011 2.736 2.668 4184

Northwest prices drag on maintenanceDemand in the Pacific Northwest will continue to remain relatively

flat throughout the weekend, increasing slightly by around 40 MMcf on Saturday to hold near 1.2 Bcf.

Similarly, Rockies demand will remain mostly unchanged from Friday’s projected demand level of 1.4 Bcf.

Gas Transmission Northwest-Kingsgate experienced one of the largest upward movements on Friday, adding almost 8 cents as planned pipeline maintenance is expected to begin on July 10 and continue through July 16 and is “likely to restrict exports into the US Northwest at the Kingsgate hub” by an average of about 400 MMcf/d.

Southwestern spot prices were primarily down on Friday as seasonal temperatures in both the Los Angeles and Phoenix markets kept demand stable around 8.0 Bcf/d heading into the weekend.

High temperatures in Los Angeles are expected to average around the upper 70s throughout the weekend, about 5 degrees above the seasonal average, while Phoenix is expected to experience temperatures around 108 degrees, about level with seasonal norms.

— Market Staff Reports

Minor leak shuts down California storage fieldLeaks continue to rock natural gas storage in California as a second major facility in the state was shut down last week.

A leak discovered at Pacific Gas & Electric’s McDonald Island gas storage facility prompted the company to temporarily shut down all injection and withdrawal activity.

McDonald Island serves as PG&E’s largest underground storage facility. Located on an island in the Sacramento-San Joaquin River Delta, it holds a maximum working gas capacity of 82 Bcf.

The leak was discovered during a recent routine investigation.This is now the second major California gas storage field forced to

shut down. Southern California Gas Company’s Aliso Canyon storage field, which is also its largest, has been shut down since last October when the leak was initially discovered.

After finally being plugged in February, the facility had leaked 4.65 Bcf of methane into the atmosphere. It remains shut down as rigorous testing of all 114 wells at the site must occur before normal operations resume.

The Aliso leak prompted California’s Department of Conservation’s Division of Oil, Gas and Geothermal Resources to implement emergency rules last February requiring more regular testing of all storage fields, which is how the McDonald Island leak was found.

well tests ordered despite low methane releaseHowever, the magnitude of the McDonald Island leak pales in

comparison to the Aliso Canyon leak, which at one point was losing methane at the rate of 60,000 kilograms per hour. Also, unlike Aliso Canyon, which is nestled next to the affluent Porter Ranch Community and forced thousands to temporarily relocate, the nearest urban enclave to McDonald Island is more than three miles away.

“After being notified of these low-level emissions earlier this month, flyovers were commissioned by the California Energy Commission and later by PG&E to confirm and measure the emissions,” said Kenneth Harris, oil and gas supervisor of DOGGR. “The data obtained by these flyovers show a very low release ranging from

mailto:[email protected]

5



236 kg/hr. to 763 kg/hr., which is similar to, or only slightly above, background levels at natural gas storage facilities.”

Although the leak is minor, heightened concerns over storage field safety in the Golden State prompted the shutdown. Out of the 87 wells scattered across the island, leaks were identified in 10 of those, according to the DOGGR. Two of those, identified as Whisky Slough #3E and Turner Cut 7N, have already been isolated from the reservoir.

“While the emissions levels are low, given the number of wells with detectable methane emissions, DOGGR has directed PG&E to test all wells at the facility,” Harris said.

The leaks appeared to be most prevalent in the “conductor pipe annulus outside of the surface casing.”

“While we do our inspections we’ve temporarily stopped withdrawing and injecting gas at the facility,” said Greg Snapper, PG&E spokesman. “There’s a lot of gas supply in the system so we’re able to meet customers’ natural gas needs using our other facilities. We moved up our annual inspections for the facility instead of waiting until later this fall. After we complete our inspections, we could restart withdrawing and injecting gas by September.”

shut-down takes pg&e’s largest field offlineReliability concerns still abound in southern California where the

state’s largest storage field, Aliso Canyon, located outside Los Angeles, is currently offline until at least later this summer. Now, the largest storage field in the San Francisco area is temporarily shut down as well.

PG&E directly owns and operates three natural gas storage facilities – Los Medanos, Pleasant Creek and McDonald Island. McDonald Island has the largest working gas capacity at 82 Bcf, while Los Medanos and Pleasant Creek contain 18 Bcf and 2.3 Bcf, respectively.

PG&E confirmed McDondal Island’s current inventory sits at 75 Bcf, but that not be available until September at the soonest.

However, PG&E does have a 25% ownership of the Gill Ranch field, while the Lodi, Wild Goose and Central Valley storage fields are all owned and operated by third parties but have access to PG&E’s system, which would allow the utility to draw gas from other sources to meet local demand if necessary.

The outage at one of the largest storage fields on PG&E’s system may cause issues both in the short- and long-term, as maintenance on the southern portion of the pipeline, along the Baja Path, will restrict operating capacity to 53% (or 600 MMcf/d) of normal at the Kettleman compressor station from July 11 through July 23.

east texas

Agua Dulce Hub IGBAV04 2.808 0.140 2.816 2.800 85

Carthage Hub IGBAF04 2.779 0.061 2.792 2.747 424

Florida Gas, zone 1 IGBAW04 2.777 0.051 2.793 2.762 539

Houston Ship Channel IGBAP04 2.759 0.053 2.787 2.747 1405

Katy IGBAQ04 2.751 0.029 2.784 2.723 2870

NGPL, STX IGBAZ04 2.696 -0.004 2.716 2.680 326

NGPL, Texok zone IGBAL04 2.699 0.019 2.737 2.668 1940

Tennessee, zone 0 IGBBA04 2.673 0.017 2.706 2.634 585

Texas Eastern, ETX IGBAN04 2.733 -0.012 2.738 2.727 75

Texas Eastern, STX IGBBB04 2.761 0.053 2.773 2.741 423

Transco, zone 1 IGBBC04 2.754 0.073 2.769 2.739 155

Transco, zone 2 IGBBU04 2.739 0.087 2.740 2.736 52

louisiana/southeast

ANR, La. IGBBF04 2.741 0.038 2.761 2.716 901

Columbia Gulf, La. IGBBG04 2.752 0.038 2.768 2.727 1030

Columbia Gulf, mainline IGBBH04 2.736 0.035 2.764 2.704 3137

Florida city-gates IGBED04 4.237 0.771 4.414 3.914 247

Florida Gas, zone 2 IGBBJ04 2.817 0.062 2.846 2.796 882

Florida Gas, zone 3 IGBBK04 2.874 0.078 2.903 2.823 1825

Henry Hub IGBBL04 2.846 0.065 2.885 2.788 1662

Southern Natural, La. IGBBO04 2.775 0.047 2.804 2.738 2663

Tennessee, La., 500 Leg IGBBP04 2.791 0.071 2.818 2.755 1220

Tennessee, La., 800 Leg IGBBQ04 2.741 0.025 2.774 2.716 2620

Texas Eastern, ELA IGBBS04 2.741 0.050 2.750 2.725 501

Texas Eastern, M-1 30-inch (Kosi) IGBDI04 2.742 0.060 2.751 2.705 235

Texas Eastern, WLA IGBBR04 2.754 0.056 2.764 2.732 915

Texas Gas, zone 1 IGBAO04 2.719 0.035 2.749 2.678 2029

Texas Gas, zone SL IGBBT04 2.744 0.070 2.745 2.729 66

Transco, zone 3 IGBBV04 2.766 0.034 2.801 2.747 1036

Transco, zone 4 IGBDJ04 2.801 0.046 2.837 2.769 4494

Trunkline, ELA IGBBX04 2.643 0.014 2.657 2.633 26

Trunkline, WLA IGBBW04 2.750 0.085 2.750 2.750 4

Trunkline, Zone 1A IGBGF04 2.701 0.028 2.746 2.681 463

rockies/Northwest

Cheyenne Hub IGBCO04 2.483 -0.079 2.505 2.424 850

CIG, Rocky Mountains IGBCK04 2.459 -0.067 2.476 2.427 234

GTN, Kingsgate IGBCY04 2.160 -0.191 2.213 2.124 1270

Kern River, Opal plant IGBCL04 2.469 -0.142 2.510 2.431 2846

Northwest, Can. bdr. (Sumas) IGBCT04 2.119 -0.325 2.182 1.993 551

Northwest, s. of Green River IGBCQ04 2.424 -0.220 2.453 2.399 196

Northwest, Wyo. Pool IGBCP04 2.429 -0.132 2.471 2.406 104

PG&E, Malin IGBDO04 2.462 -0.180 2.523 2.424 2140

Questar, Rocky Mountains IGBCN04 2.449 -0.125 2.449 2.449 32

Stanfield, Ore. IGBCM04 2.326 -0.173 2.371 2.304 284

TCPL Alberta, AECO-C* IGBCU04 2.256 -0.016 2.334 2.181 7719

Westcoast, station 2* IGBCZ04 2.126 0.118 2.149 2.099 816

White River Hub IGBGL04 2.468 -0.129 2.496 2.424 742

southwest

El Paso, Bondad IGBCG04 2.496 -0.122 2.521 2.454 1025

El Paso, Permian Basin IGBAB04 2.509 -0.118 2.566 2.474 2391

El Paso, San Juan Basin IGBCH04 2.499 -0.132 2.529 2.474 1270

El Paso, South Mainline IGBFR04 2.661 -0.198 2.696 2.604 1033

Kern River, delivered IGBES04 2.602 -0.241 2.647 2.571 1661

PG&E city-gate IGBEB04 2.934 -0.067 3.000 2.887 3429

PG&E, South IGBDM04 2.604 -0.208 2.616 2.584 585

SoCal Gas IGBDL04 2.626 -0.203 2.669 2.556 2447

SoCal Gas, city-gate IGBGG04 2.638 -0.372 2.768 2.577 3022

Transwestern, Permian Basin IGBAE04 2.514 -0.122 2.541 2.481 655

Transwestern, San Juan IGBGK04 2.501 -0.135 2.528 2.470 423

Waha IGBAD04 2.639 -0.021 2.699 2.529 2728

*NOTE: Price in C$ per gj

weekly weigHted aVerage priCes 07/02-07/08 wkly total 2016 -/+ High low Volumes

PG&E TOTAL SYSTEM STORAGE INVENTORY(Bcf)

Source: Platts Analytics/Bentek

50

100

150

200

250

DecNovOctSepAugJulJunMayAprMarFebJan

5-Year Average201420152016Capacity

Range

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The Kettleman compressor separates supply from interstate pipelines in southern California, and much of PG&E’s market area where all of the storage facilities are located.

Temperatures are expected to reach near 77-degrees Fahrenheit in California by Thursday, the same peak that hit the region during the most recent change of months from June to July. The outage of McDonald Island, coupled with the Baja Path maintenance, will likely cause further increased reliance on storage withdrawals to meet peak summer demand and place upward price pressure at PG&E citygates.

aliso experiences another leakWhile Aliso Canyon is in the process of testing all of its wells, which

it hopes to have completed before summer ends, a new leak was discovered at the site last weekend.

Last Saturday, during a routine inspection, SoCal Gas personnel discovered a minor leak on a small pipeline near one of the site’s wells.

“Personnel isolated the leak, stopping the flow of gas and repairs were made on Sunday,” said SoCal Gas, a subsidiary of Sempra Energy, in a statement. “Company personnel performed a thorough assessment and determined the source of the gas to be a small leak from a nearby, buried three-inch pipeline not associated with the well’s operation.”

Although minor, the latest Aliso leak has reinvigorated activists groups that have been calling for a permanent closure of the field.

— Brandon Evans, John Hilfiker

June flows offer insight into Vector’s future ANALYSIS Declining imports from Vector Pipeline may offer insight into how Dawn flows will be impacted when the Northern Access 2016 project comes online near the end of next year.

National Fuel’s Northern Access 2016 project plans to bring an additional 350 MMcf/d to the existing Chippawa interconnect with TransCanada Pipeline.

When completed, Northern Access 2016 will provide US Northeast producers an additional outlet for their supply in Eastern Canada. The US Northeast has already been flowing significant volumes into Eastern Canada, with the Niagara interconnect flowing a year-to-date average of 625 MMcf/d into Ontario and the Chippawa interconnect averaging another 150 MMcf/d.

The project, initially slated to come online in November 2016, was delayed earlier this year to November 2017. The delay is attributed to Seneca Resources, National Fuel’s wholly owned exploration-and-production subsidiary, electing to reduce the pace of its drilling program in the Marcellus Shale. Seneca cited low near-term natural gas prices as the reason for the reduction.

Northern Access 2016 could increase total Canadian imports through this area by 45% to 1.125 Bcf/d. TransCanada has indicated that more than 1 Bcf/d of the capacity at Niagara and Chippewa is contracted to move volumes into Eastern Canada, suggesting this corridor is likely to flow at, or near capacity going forward.

The extra supply Northern Access 2016 will bring into eastern Canada will be flowing into a market that has seen essentially no demand growth over the past several years. Gas demand in eastern Canada has averaged a remarkably flat 3.5 Bcf/d over the past five-years, and Platts Bentek is not forecasting any growth over the next five years.

A 350 MMcf/d increase in eastern Canadian supply and no demand growth suggest eastern Canadian inflows from another supply source could be squeezed out, and if Dawn flows in June are any indication, Vector Pipeline could see less utilization when Northern Access 2016 comes online next year.

eastern Canada relying less on Vector importsEastern Canada has relied less on Vector imports this summer

with storage inventories significantly above normal levels. US imports from Vector at the St. Clair interconnect averaged just 0.5 Bcf/d last month, its lowest monthly average since February 2007, according to Platts Bentek.

Dawn inventories began June at 154 Bcf, which was about 54 Bcf more than the five-year average and only 111 Bcf below Dawn’s stated capacity. This prompted Dawn to inject only 0.9 Bcf/d in June, considerably weaker than the five-year average of 1.2 Bcf/d.

In addition to weak injection demand, imports from the Marcellus at the Niagara and Chippewa interconnects have averaged almost 0.8 Bcf/d in June, compared with 0.45 Bcf/d during the same time last year. At the same time, eastern Canada demand was flat year-over-over in June, averaging 2.186 Bcf/d, compared to 2.23 Bcf/d during the

Michigan

IndianaOhio

Pennsylvania

New York

Ontario

UNITED STATES

CANADA

NiagaraChippawa

Pipeline interconnectsTransCanada’s systemUnion gasVector pipeline

Source: Platts

NIAGARA�CHIPPAWA COMPETE WITH VECTOR

CANADIAN IMPORTS FROM VECTOR

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

Jun-16Jun-15Jun-15Jun-13Jun-12Jun-11

(Bcf/d)

Source: Platts


7



same period last year.Stagnant demand in eastern Canada, along with increased imports

from the US Northeast, have meant that Vector imports at the Michigan-Ontario border are getting squeezed out. Vector’s 0.5 Bcf/d average in June is 320 MMcf/d weaker than June 2015 and 400 MMcf/d weaker than June 2014.

If June flows are any indication of what less need for non-Marcellus gas in eastern Canada could look like, Vector may see its market share in Ontario and Quebec decline when Northern Access 2016 comes online.

— Richard Frey, Brandon Evans

Higher ethane demand lessens rejection: eiaThe recent increase in ethane prices has resulted in less volumes of the natural gas liquid being rejected into the natural gas stream in wet-gas regions such as parts of the Marcellus Shale and more ethane being profitably sold, according to a recent Energy Information Administration report.

“Since January 2016, there have been indications that the portion of ethane recovered as a percent of total natural gas plant liquids (NGPL) produced has generally been increasing, while the heat content of natural gas delivered to consumers, an indicator of NGPL-content (primarily ethane) in pipeline gas, has been declining,” according to the report.

Ethane prices had been at or below natural gas prices since late 2012, but ethane began selling at a premium to gas around the beginning of 2016 as ethane demand grew and infrastructure growth lagged supply increases. In June, the price of ethane averaged $3.14/MMBtu, 18% higher than the average Henry Hub gas price for the month.

As a result, gas processors are finding it more economical to separate the ethane from the gas stream, rather than rejecting the NGL by leaving it in the gas stream where it would be sold at natural gas prices, Warren Wilczewski, one of the authors of the report, said in an interview Friday.

“If I had to pick someone who particularly benefits from this, it would be the midstream processors who have invested in the more specialized equipment to extract the ethane,” said Wilczewski, an industry economist in EIA’s Office of Energy Analysis.

Unlike heavier NGLs, such as propane, butanes and natural gasoline, ethane can remain in the processed gas that is transported on interstate pipelines so it is up to the discretion of the processing plants as to whether or not to extract ethane, EIA said.

“Once you blend it into the gas stream you get only the gas cost,” Wilczewski said. “To some extent, that’s one of biggest wins: the ability to surplus, basically to take a market that was previously constrained and allows it to expand.”

One potential beneficiary of the re-invigorated ethane market likely will be Marathon Petroleum, whose affiliate MPLX recently acquired MarkWest Energy Partners, Wilczewski said. The latter company “had heavily invested in the cryogenic processing, which allows a large amount of recovery of ethane from the stream,” he said. “They can now monetize that at ethane value rather than methane value.”

Bump in ethane prices traced to uptick in demandThe EIA traced the uptick in ethane prices this year to higher

ethane consumption by Gulf Coast petrochemical plants, as well as the start of operations at the Sunoco ethane export terminal at Marcus Hook, Pennsylvania in early March. The opening of that facility provided gas producers in the area with an additional market outlet for 35,000 b/d of ethane.

“US export capacity is expected to grow further in the third quarter of this year, when Enterprise Products Partners commissions its ethane export terminal in Morgan’s Point, Texas, which has a planned 200,000 b/d capacity,” the report says.

“By comparison, total U.S. ethane production in April 2016 averaged 1.3 million b/d.”

Demand for ethane from the Marcellus and Utica shales gas producing plays is expected to ramp up in the next several years. Last month Shell Chemical announced it had decided to go ahead with plans to build a $4 billion ethane cracker that would be the first of its kind in the Northeast. The project, which is expected to use about 86,000 b/d of ethane as a feedstock, is expected to come online in 2022.

US ethane production (after rejection) reached a new record of 1.28 billion b/d in April, up by 7,000 b/d from March, according to monthly data released by the EIA on June 30.

Total US NGL production is up by nearly 200,000 b/d or 7% over last year, with nearly 140,000 b/d of this rise coming from increased ethane production, according to Platts Analytics unit Bentek Energy. Since the EIA reports ethane production after rejection, this is indicative of increased ethane recovery.

Morgan’s point exports seen to further up demandPlatts Analytics’ Bentek Energy estimates that ethane is being

recovered in anticipation of exports beginning from Enterprise’s Morgan’s Point terminal in the third quarter of this year, and about 350,000 b/d of new ethane demand that is expected to come online through 2017 from steam cracker expansions and new builds.

Ethane and propane prices at Mont Belvieu have increased by 18% and 10% respectively, in the month of June. Ethane prices at Mont Belvieu hit a two-year high of 24.87 cents/gallon on June 9, after Shell’s decision to proceed with its petrochemicals complex in Monaca, Pennsylvania. Ethane closed at 23 cents/gallon on Friday.

ETHANE PREMIUM OVER GAS PRICE VS. ETHANE PRODUCTION

-0.5

-0.2

0.1

0.4

0.7

1.0

1.3

1.6

Jun-16Apr-16Jan-16Sep-15Jun-15Apr-15Jan-15

($/MMBtu)

Source: Platts Bentek

Ethane production (right) Mont Belvieu ethane/Henry Hub gas

(Mb/d)

0

200

400

600

800

1000

1200

1400


8



Combined with the volatility in gas prices, the premium of ethane over natural gas has fluctuated, indicating changes in marginal ethane recovery. The price spread between Mont Belvieu ethane and Henry Hub cash prices for gas averaged $1.24/MMBtu in the second week of June but is now down to about 50 cent to 60 cents/MMBtu, due to both a decline in ethane prices and rise in the gas price.

So far in July, Henry Hub prices gas prices have gained about 5 cents/MMBtu this month, to close at $2.76/MMBtu Friday.

— Jim Magill, Prachi Mehta

panda gas plants begin service in pennsylvaniaPanda Power Funds’ new 829-MW Liberty combined-cycle natural gas plant in Towanda, Pennsylvania, entered full commercial operation on Thursday and its sister, the 829-MW Patriot gas plant in Williamsport, Pennsylvania, should be online soon as the Dallas-based private equity firm looks for take advantage of shale gas development in the region.

In all, Panda is building three large, combined-cycle gas plants in Pennsylvania. Its 1,124-MW Panda Hummel station under construction in Snyder County is one of the largest coal-to-gas replacement projects in the US.

“Liberty was the first gas plant born of the Marcellus Shale,” Panda spokesman Bill Pentak said in an interview. Liberty takes gas from the Transco Leidy pipeline.

Before the end of summer, Patriot is expected to be in commercial operation as well, according to Pentak. “It’s getting close,” he said. Kinder Morgan’s Tennessee Gas Pipeline will supply gas for the new plant.

In terms of gas usage, if Liberty and Patriot were running at 800 MW they each would require about 120,000 MMBtu/day. Hummel’s usage would be about 180,000 MMBtu/day, Pentak said.

Gas deliveries to the 829-MW Panda Liberty plant first began at the start of this year, with nominations averaging 3,800 Mcf/d in January. Gas deliveries to the plant increased in earnest in March, when flows peaked at 65 MMcf/d and averaged 23 MMcf/d for the month. More recently, deliveries to the plant have risen substantially, with July month-to-date volumes averaging 122 MMcf/d. The highest daily volume was 138 MMcf/d on June 20. The Liberty plant receives gas from Tennessee Gas Pipeline at the South Jersey Resources-operated Beirne Hill Sales meter.

Deliveries to the 829-MW Panda Patriot plant began on June 21, ramping up quickly to as high as 110 MMcf/d by the end of June. Month-to-date deliveries this July have so far averaged just under 98 MMcf/d. The Patriot plant receives gas off Transcontinental Gas Pipe Line’s Leidy Line via the UGI Muncy delivery meter, operated by UGI Penn Energy.

Together, Liberty and Patriot are expected to have more than 50 full-time employees.

Hummel is more unusual projectHummel, in fact, is a more unusual project than Liberty and Patriot.“It’s a unique facility,” Pentak said, noting the plant is designed to

replace the former 400-MW Sunbury coal-fired plant retired in 2014 following a 65-year life. Sunbury originally was built by Pennsylvania Power & Light.

Hummel, being built on the banks of the Susquehanna River, is scheduled for commercial operation in 2018.

According to Pentak, Hummel will be supplied by the Marc 1 and Transcontinental Gas Pipe Line.

Formed in 2010 by the former senior management and energy professionals at Panda Energy International, an independent power developer, Panda Power Funds’ foundation “was really to take advantage of shale gas,” Pentak said.

“What’s going on in the power industry, from coal to gas, is the biggest change we’ve seen, and we’ve been doing business since 1982,” he said, referring to Panda’s initial creation.

Panda Power Funds also is constructing the 778-MW Stonewall combined-cycle gas plant outside of Leesburg, Virginia. It is expected to be operational in early 2017.

panda on lookout for more projectsMore gas plants may be in Panda’s pipeline as well.“We’re a power developer, so we’re always looking for the next

power project,” he said. “That never stops.”Panda looks for “certain criteria” in site selection, Pentak said.

He did not elaborate except to point out that Panda currently operates only in the PJM Interconnection and Electric Reliability Council of Texas regions.

“We think the PJM market makes a lot of sense,” he said.Panda also has two 758-MW gas plants in Temple, Texas, and a

758-MW plant in Sherman, Texas.Under development by the company is a 990-MW combined-cycle

gas project in Brandywine, Maryland.Panda says on its website that no other fuel source is more

readily available than natural gas to meet the country’s growing demand for energy.

That demand has been driven in the past few years by the retirement of thousands of megawatts of coal generation, mainly in Midwestern and Eastern states.

Compared with coal, gas can reduce carbon dioxide emissions by up to 60%, with virtually no sulfur dioxide, mercury or particulate emissions.

— Bob Matyi, Eric Brooks

iNgaa offers alternatives to pHMsa safety ruleThe Interstate Natural Gas Association of America last week joined other industry groups in finding fault with the Pipeline and Hazardous Materials Safety Administration’s massive proposed gas transportation safety rule.

While saying it backed the intent of the proposed rule, the group disagreed in many cases with the specific means proposed by PHMSA, it said.

INGAA’s 219-page comments called the proposed rule “an overly complicated and rigid approach to pipeline safety that threatens to slow the industry’s progress toward achieving shared safety goals and improving safety technologies.”

Under the proposal, “operators would be required to allocate significant resources to activities that do little, if anything, to increase



9



the margin of safety,” the comments said.PHMSA’s rule proposed in April would expand the scope of gas

pipeline rules to cover 70,000 miles of line not currently regulated, and extend reporting requirements to 300,000 miles of gathering lines. As described by the agency, the rule would take fresh look at integrity management, make recommendations for addressing data gaps and improving data integration, as well as suggesting new and innovative methods to assess and address risks.

Also included are new assessment and repair criteria for gas pipelines and plans to extend the protocols to areas of medium population density, to be called “moderate consequence areas.”

pressure test rules called into questionIn its comments, INGAA listed three provisions it believes PHMSA

should strike or modify to ensure its rulemaking truly enhances safety.It urged PHMSA to allow the use of alternative means for validating

maximum allowable operating pressure such as in-line inspection. INGAA said the proposed rule’s emphasis on hydrostatic pressure tests would constrain adoption of advanced technologies that can provide more information and improve safety.

The industry group also asked PHMSA to strike a requirement for use of spike hydrostatic pressure testing for legacy pipe, suggesting it would be “inappropriate” to mandate use of the technique to confirm MAOP. The technique was developed for managing stress corrosion cracking and mandating it for MAOP would significantly harm the environment and disrupt market reliability without improving safety, INGAA said.

INGAA also asked PHMSA to remove “overly prescriptive” material verification criteria that the group said would raise risk, unnecessarily disrupt service and add excessive costs.

Conflicts seen with other agency requirementsIn addition, INGAA argued that the rule fails to recognize

implications for compliance with other federal requirements, including those set by the FERC and the Environmental Protection Agency.

“The increased methane emissions associated with hydrostatic pressure testing and certain repairs run counter to the president’s goals of reducing methane emissions, as reflected by the new EPA rule restricting methane emissions from certain oil and gas facilities. Removing lines from service to perform hydrostatic testing would raise issues under FERC’s regulations and policies,” INGAA said in a statement.

INGAA also found fault with the cost-benefit analysis in the proposal, saying it fell short of requirements to perform a risk-based analysis, underestimated costs while overstating benefits and missed the cumulative impact of individual proposed rules. “[S]ome of the proposal’s most burdensome provisions apply to almost all transmission pipelines,” the group said.

It asked PHMSA to hold a public workshop to allow interested parties to discuss concerns and alternatives.

In airing its views on the proposal, INGAA followed earlier remarks by the American Petroleum Institute. As last Thursday’s deadline for comments on the proposal approached, API called the proposed rule arbitrary and capricious, overreaching and contrary to a statutory

directive to use a risk-informed approach.The American Gas Association outlined another strong critique to

reporters last month. The group representing distributors argued that the proposal “imposes prescriptive and burdensome requirements on operators that, in the end, will likely not address the perceived regulatory pipeline safety benefits.” AGA included alternative approaches to the rulemaking along with its comments, the group said Thursday.

— Maya Weber

us lNg exports driving break from oil-linkageThe expected growth of US LNG exports is driving a transformation in the global market that could lead to the end of oil-linked pricing, according to report released Friday by Bernstein Research.

Recent changes in market sentiment, pricing and perceived security of supply have accelerated the push for a decoupling of LNG and oil prices, coming particularly from Asian consumers.

In May, the call for change appeared to reach an inflection point when Japan’s Ministry of Economy, Trade and Industry declared the LNG to crude linkage as “no longer justifiable.”

Since the advent of the LNG industry in the 1960s, oil-linked pricing has served an important function in the industry. For sellers, long-term contracts provide certainty for offtake volumes and pricing. For buyers, such contracts offer security of supply. Not least of all, contracts have reduced investment risks for financiers that have invested billions on liquefaction and export projects.

While the shift away from the added security offered by oil-linked contracts appears to be global, US exports have played an important role in that evolution, according to Bernstein.

us exports fortify buyers’ market sentimentThe expected growth of US LNG exports is responsible, in several

ways, for the drive away from oil-linked pricing.First, US exports are contributing to a market sentiment

characterized by oversupply. This situation, according to Bernstein, is giving buyers a chance to “flex their muscles,” by calling for changes to both contracts and pricing.

US exports thus far have contributed only marginally to excess supply. However, broad expectations for a buyers’ market through the end of the decade do depend quite heavily on the global availability of US natural gas.

Second, US LNG is about more than just the export of US natural gas—it’s about the export of Henry Hub-linked pricing. The distinction marks a fine line, but points to the growing relevance of Henry Hub-linked hedging and trading for global natural gas buyers.

Finally, the growth of US shale gas supply has fortified that notion

platts gas is oN liNkediNFollow platts gas to get tHe latest iNdustry News aNd exClusiVe CoNteNt

www.linkedin.com/company/platts-natural-gas


10



of “a gas-long world in the mind of many,” said Bernstein. As a consequence, diminishing concerns over security of supply are giving buyers greater confidence in the market and reducing the perceived need for long-term contracts.

asian market poses challenges to hub pricingWhile buyers seem more ready now than ever before to move away

from oil-linked LNG pricing, several attributes of the Asian gas market pose challenges to the emergence of hub-based pricing.

The phasing-out of oil-linked LNG in Asia, according to Bernstein, depends heavily on the viability of natural gas trading hubs in the region.

In order for a trading hub to emerge, the market must first offer open access—not only to LNG terminals, but also to storage and international pipelines. Secondly, a hub must provide fully transparent and trustworthy pricing mechanisms. Third, a hub must be liquid enough to support spot pricing along with forwards, futures and swaps markets.

Bernstein identifies Singapore, Shanghai and Tokyo as potential candidates for an Asian gas hub, but notes that none of them is yet capable of meeting all three of the above-named requirements.

What Singapore offers in open access and transparency, it lacks in liquidity—a factor that would be difficult to build up on a small island nation. While Shanghai is a highly liquid and well-connected market, open access and transparency are questionable at best, according to Bernstein.

Tokyo, meanwhile, offers liquidity and has been working on building up transparency. As an island nation with a highly segmented gas grid though, Japan is lacking in connectivity and open access.

— J. Robinson

Court decisions uphold FerC lNg reviewTwo federal appeals court decisions affirming FERC’s environmental review of LNG export projects are likely to increase certainty that developers can rely on the commission’s decision-making, according to legal experts.

That said, evolving challenges from environmental groups are expected.

The DC Circuit Court of Appeals on June 28 rejected the Sierra Club’s challenges to the environmental reviews for the Freeport and Sabine Pass LNG export projects. The court found FERC did not need to weigh the environmental impact of upstream gas development, because DOE and not FERC makes the decision to authorize the gas exports, which environmentalists argue spur added production.

Some saw the Freeport ruling as having implications for natural gas pipeline permitting more broadly inasmuch as it backed FERC’s reasoning that it did not need to take into account induced natural gas production in National Environmental Policy Act review of projects. Environmentalists, on the other hand, were more inclined to describe the rulings as instructive of the kind of evidence they would need to bolster their case.

In the near term, the decisions shift the legal battle to DOE,

where environmentalists have made similar arguments critical of NEPA reviews.

Nathan Matthews, an attorney for the Sierra Club, said the rulings left open the avenue for challenges of DOE’s NEPA reviews on the issue of exports inducing production. Sierra Club’s challenge to DOE’s Freeport export approval has already been briefed at the DC Circuit, a second appeal is pending in the Cove Point LNG case, and other appealable orders came out of DOE in May, he noted.

At FERC, he said, environmentalists’ challenges to projects also involve concerns entirely within FERC’s purview that would be unaffected by the court orders. For instance, he pointed to local impacts such as harm to endangered species, tourism and shrimping, raised in comments on LNG projects in Texas.

The group has not yet decided whether to request rehearing on the DC Circuit rulings, he said.

ruling increases confidence in FerC actionFrom an industry perspective, Charlie Riedl, executive director of

the Center for Liquefied Natural Gas, saw the ruling as bolstering predictability.

“In the environment we’re in with the low cost of LNG, any time

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11



Table and graphs are created using Platts M2MS-Gas data. Forward assessments as basis to the Henry Hub and full values are available for periods spanning 10 years. To see a sample and �nd information on how to subscribe to the full data set go to www.platts.com/risk. For more information on Platts services, please call +1-800-PLATTS8. For editorial questions, call Mark Callahan +713-658-3211.

Northwest, Rockies: Basis market vs NYMEX

($/MMBtu)

1.7

2.1

2.5

2.9

3.3

08-Jul29-Jun21-Jun13-Jun03-Jun25-May

Prompt month NYMEXPrompt month basis

2.0

2.5

3.0

3.5

4.0

08-Jul29-Jun21-Jun13-Jun03-Jun25-May

($/MMBtu)

Northwest, Rockies: Key packages, last 30 days

Winter 16-17Summer 16*Cal 17

August 16

0

1

2

3

4($/MMBtu)

Northwest, Rockies: Forward curve

Spot price, last 30 days

Cal 1

8

Winter 1

8-1

9

Cal 1

7

Winter 1

7-1

8

January 17

Summ

er 17

Winter 1

6-1

7

Summ

er 16

*

Aug

ust 16

Cal 1

9

Summ

er 18

October 1

6

Novem

ber 16

Decem

ber 16

Septembe 1

6

Natural gas financial basis swaps were mixed Friday, with some points in the Northeast having the biggest increases as the NYMEX prompt-month contract rebounded slightly.

The NYMEX August natural gas futures contract settled at $2.801/MMBtu, up 2.4 cents.

On the week, however, the prompt contract has given up a combined 18.6 cents, mostly driven by Tuesday’s 22.3-cent decline.

In the Northeast, Transcontinental Gas Pipe Line Zone 6 New York August basis slipped 2 cents to minus 56 cents/MMBtu.

Looking ahead to the next heating season, Transco winter 2016-17 basis climbed to its highest price in the last 30 days, jumping just over 11 cents to plus $3.50/MMBtu.

Market assessments are considered preliminary and based on market activity on IntercontinentalExchange at 2:25 pm EDT (1725 GMT).

On Thursday, the Federal Energy Regulatory Commission issued a certificate of public convenience and necessity for Transco’s New York Bay Expansion Project. The project is designed to provide 115,000 Dth/d of incremental firm transportation service for the Brooklyn Union Gas Company. The project also includes 65,000 Dth/d from Compressor Station 196 in York, Pennsylvania, to the Rockaway Transfer Point on Transco’s New York Bay Lateral as well as 50,000 Dth/d from Compressor Station 195 to the Narrows Meter Station in Richmond County, New York, according to the FERC certificate.

The project has a fourth-quarter 2017 in-service date, according to

the expansion project’s website.According to Platts Analytic’s Bentek Energy, the expansion project

may put downward pressure on Transco winter 2017-18 basis, which has recently traded about 4 cents over the winter 2016-17 strip.

Nearby, Texas Eastern Transmission M-3 August basis added a cent to reach minus $1.13/MMBtu.

Upstream in Appalachia, Dominion Transmission South Point August basis was up a cent to reach minus $1.29/MMBtu.

In the Upper Midwest, prices had little movement as Chicago city-gates August basis held flat from Thursday after trading around minus 6.75 cents/MMBtu.

In Western Canada, AECO-NIT August basis dipped nearly a cent to minus $1.055/MMBtu.

Along the West Coast, Pacific Gas & Electric city-gates August basis was down 2 cents to plus 26.75 cents/MMBtu.

The latest eight- to 14-day outlook from the US National Weather Service called for above-average temperatures to spread across nearly the entire continental US, likely keeping gas demand high in the second half of the month. Only portions of the Pacific Northwest were forecast at or below seasonal norms.

Southern California Gas August basis moved higher, adding 1.5 cents to trade at minus 4 cents/MMBtu. Further along the curve, SoCal winter 2016-17 basis was up about a cent to reach plus 17 cents/MMBtu.

— Curt Mrowiec

Financial basis swaps mixed with Northeast seeing increases; NyMex rebounds

Platts M2Ms Forward Curve — Natural Gas, Jul 8 ($/MMBtu)

prompt month: aug 16

Algonquin, city-gates 0.280Transco, zone 6-NY -0.540Texas Eastern, M-3 -1.118Columbia Gas, Appalachia -0.108Dominion, South Point -1.295Transco, zone 3 -0.030Transco, zone 4 -0.015Southern Natural, LA -0.033Tennessee, 500 Leg -0.061Florida Gas, zone 3 0.095Columbia Gulf, mainline -0.083Houston Ship Channel -0.046NGPL, Texok -0.075Chicago city-gates -0.068MichCon city-gate -0.060Dawn, Ontario -0.035Panhandle, TX-Okla. -0.230Northern, Ventura -0.148Northern, demarc -0.143Waha -0.125El Paso, Permian Basin -0.175El Paso, San Juan Basin -0.161PG&E city-gate 0.265PG&E, Malin -0.173SoCal Gas -0.035Northwest, Rockies -0.238Northwest, Sumas -0.610AECO, Alberta -1.053summer season is april-october. winter is November-March. *Balance-of-season.


12



sHale Value CHaiN assessMeNts, Jul 8 $/MMBtu +/-

Gulf Coast ethane fractionation spread 0.271 0.070

Gulf Coast E/P mix fractionation spread 0.140 0.089

E/P mix Midcontinent to Rockies fractionation spread -0.115 -0.027

E/P mix Midcontinent fractionation spread -0.195 -0.007

National raw NGL basket price 4.999 0.046

National composite fractionation spread 2.319 0.116

The methodology for these assessments is available at:www.platts.com/IM.Platts.Content/MethodologyReferences/MethodologySpecs/shale-value-chain.pdf

NyMex HeNry HuB gas Futures CoNtraCt, Jul 8 settlement High low +/- Volume

Aug 2016 2.801 2.825 2.748 0.024 138168Sep 2016 2.788 2.812 2.740 0.024 58063Oct 2016 2.827 2.849 2.778 0.025 39984Nov 2016 2.990 3.000 2.949 0.033 20516Dec 2016 3.251 3.255 3.207 0.037 14898Jan 2017 3.384 3.389 3.342 0.037 20277Feb 2017 3.370 3.377 3.335 0.034 5023Mar 2017 3.318 3.322 3.285 0.031 9658Apr 2017 3.082 3.085 3.056 0.018 11661May 2017 3.053 3.058 3.032 0.012 4010Jun 2017 3.089 3.094 3.070 0.010 3115Jul 2017 3.121 3.129 3.111 0.008 2301Aug 2017 3.130 3.138 3.118 0.007 1086Sep 2017 3.107 3.116 3.095 0.006 674Oct 2017 3.129 3.137 3.119 0.006 2580Nov 2017 3.179 3.183 3.168 0.007 1536Dec 2017 3.310 3.313 3.295 0.004 1485Jan 2018 3.407 3.407 3.395 0.004 859Feb 2018 3.366 3.366 3.362 0.007 143Mar 2018 3.287 3.287 3.287 0.006 259Apr 2018 2.891 2.891 2.885 0.000 375May 2018 2.858 2.858 2.858 0.001 210Jun 2018 2.884 2.884 2.884 0.001 200Jul 2018 2.915 2.915 2.915 0.001 200Aug 2018 2.924 2.924 2.924 0.001 100Sep 2018 2.901 2.901 2.901 0.002 0Oct 2018 2.919 2.919 2.919 0.002 1Nov 2018 2.991 2.991 2.991 0.002 4Dec 2018 3.135 3.135 3.135 0.002 14Jan 2019 3.251 3.251 3.251 0.002 0Feb 2019 3.219 3.219 3.219 0.002 0Mar 2019 3.156 3.156 3.156 0.002 0Apr 2019 2.871 2.871 2.871 0.002 0May 2019 2.860 2.860 2.860 0.002 0Jun 2019 2.890 3.251 3.251 0.002 0Jul 2019 2.926 2.926 2.926 0.002 0Contract data for ThursdayVolume of contracts traded: 337,405Front-months open interest:Aug, 186,636; Sep, 226,011; Oct, 108.450Total open interest: 1,058,049Data is provided by a third-party vendor and is accurate as of 5:30 pm Eastern time.

platts oil priCes, Jul 8 ($/b) ($/MMBtu)

gulf Coast spot1% Resid (1) 40.59-40.61 6.503% Resid (1) 34.01-34.03 5.44

Crude spotWTI (Aug) (2) 45.40-45.42 7.83

New york spotNo.2 (1) 53.52-53.56 8.570.3% Resid LP (3) 46.75-46.77 7.480.3% Resid HP (3) 46.50-46.52 7.440.7% Resid (3) 39.25-39.27 6.281% Resid (3) 37.25-37.27 5.96

1= barge delivery; 2= pipeline delivery; 3= cargo delivery

($/MMBtu)

HENRY HUB/NYMEX SPREAD

2.7

2.8

2.9

3.0

08-Jul07-Jul06-Jul05-Jul04-Jul

Henry Hub cash priceNYMEX front month close

there is uncertainty or doubt it tends to slow down the flow of cash. The ruling provides certainty, at least for facilities that the court ruled upon, that they had done all they needed to do environmentally.”

The precedent, he said, is significant in signaling that if one follows the environmental program that FERC laid out one should be able to get a permit.

“That should reassure investors that they will not wind up in multi-year debates in the court system,” he said.

some see ruling impacting interstate pipelinesKevin Ewing, partner at Bracewell, saw the significance of the

ruling reaching beyond LNG projects to have implications for interstate natural gas permitting reviews at FERC. “The case put in front of the court two competing views on how certain kinds of NEPA analysis should play out. A battle of ideas was really joined.”

In a 3-0 decision, the court accepted FERC’s view of how to do a NEPA analysis with respect to induced gas, he noted.

In particular, he pointed to passages in the Freeport ruling disagreeing with the environmentalists’ argument on induced production from domestic operations.

“To the extent that the associations’ argument focuses on induced production from domestic operations, we disagree. The commission reasonably explained that the asserted linkage was too attenuated to be weighed in its particular NEPA analysis,” the Freeport decision said.

However, Maya van Rossum, who heads the Delaware Riverkeeper Network, asserted that the ruling did not foreclose further challenges making the case that FERC pipeline approvals would cause more drilling and fracking, saying she did not see any red flags in the court’s language related to cumulative impacts.

To make the case, environmental groups will have to pay closer attention to contracts used to support the projects and look hard at investigations into need, she said. They have already increased the focus on that because FERC is so “cavalier” in considering contracts as proof of need for a project, she said.

Carolyn Elefant, a Washington attorney who has represented landowners, suggested that in the bigger picture the rulings don’t alter the playing field all that much.

While challenges on NEPA grounds are useful in clarifying what the law is, “I don’t think NEPA is the strongest tool as far as pipelines are concerned,” she said. Even if a challenge is successful, because of the way appeals under the Natural Gas Act are

Court decisions ... from page 10

13



officers of the Corporation: Harold McGraw iii, Chairman; doug Peterson, President and Chief Executive officer; david Goldenberg, acting General Counsel; Jack F. Callahan Jr., Executive Vice President and Chief Financial officer; Elizabeth o’Melia, senior Vice President, Treasury operations.

Gas Daily Questions? Email:naGas&[email protected]

Managers North America Gas and Power ContentRocco Canonica, +1-720-264-6626Matthew Eversman, +1-713-655-2238Beth McKay, +1-713-655-2258anne swedberg, +1-720-264-6728

EditorsBrandon Evans, +1-720-264-6671Jim Magill, +1-713-658-3229Jasmin Melvin, +1-202-383-2135Chris newkumet, +1-202-383-2141J. Robinson, +1-713-658-3257Mark Watson, +1-713-658-3214Maya Weber, +1-202-383-2244

Spot Market Editorsart Fresquez, +1-713-655-2279ashish Kothari, +1-713-655-2241Curt Mrowiec, +1-713-658-3271Charles noh, +1-713-658-3259Ryan ouwerkerk, +1-713-655-2202

AnalystsEric BrooksRichard FreyJohn HilfikerTyler JubertGeorge McGuirkMason McleanJonathan nelsonThad WalkerRoss Wyeno

Director, Global Gas and Power PricingMark Callahan

Director, Global Gas and Power ContentJames o’Connell

Global Editorial Director, Gas and Powersimon Thorne

Manager, Advertisement SalesKacey Comstock

Volume 33 / Issue 131 / Monday, July 11, 2016

Chief Content OfficerMartin Fraenkel

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structured, requiring rehearing at FERC to first be exhausted, in many cases the pipe is already in the ground.

Sandra Safro, a partner at K&L Gates, said the court decisions should be positive for LNG project developers that are still going through the FERC process. By and large, she said the decisions should be helpful to dissuade appeals on similar grounds and present strong case law to uphold FERC’s underlying decisions.

doe next in line to hear argumentsIn the wake of the rulings, Healther Palmer of Bracewell said all

eyes are likely to turn to DOE, where environmental groups will take the similar arguments about exports inducing gas production.

Yet, she too suggested the wording on cumulative impacts could have broader implications for pipeline permitting.

— Maya Weber

https://pmc.platts.com/NlPdf.aspx?nlname=Gas Daily Market Fundamentals&il=true&t=nl&m=display&ft=pdf

https://pmc.platts.com/NlPdf.aspx?nlname=Gas+Daily+Market+Fundamentals+Data&il=true&t=nl&m=download&ft=excel

https://pmc.platts.com/NlPdf.aspx?nlname=Gas Daily Price Guide&il=true&t=nl&m=display&ft=pdf


14



Basis diFFereNtial For week eNded Jul 08 Henry el paso agua transco katy kern, panhandle Chicago Col. gas soCal Hub permian dulce Zone 3 opal tx.-ok. city-gates appa. gasWeekly WACOG 2.85 2.51 2.81 2.77 2.75 2.47 2.57 2.73 2.76 2.63Henry Hub 0.34 0.04 0.08 0.10 0.38 0.28 0.12 0.09 0.22El Paso, Permian -0.34 -0.30 -0.26 -0.24 0.04 -0.06 -0.22 -0.25 -0.12Agua Dulce -0.04 0.30 0.04 0.06 0.34 0.24 0.08 0.05 0.18Transco Zone 3 -0.08 0.26 -0.04 0.02 0.30 0.20 0.04 0.01 0.14Katy -0.10 0.24 -0.06 -0.02 0.28 0.18 0.02 -0.01 0.12Kern, Opal -0.38 -0.04 -0.34 -0.30 -0.28 -0.10 -0.26 -0.29 -0.16Panhandle, Tx.-Ok. -0.28 0.06 -0.24 -0.20 -0.18 0.10 -0.16 -0.19 -0.06Chicago city-gates -0.12 0.22 -0.08 -0.04 -0.02 0.26 0.16 -0.03 0.10Col. Gas Appa. -0.09 0.25 -0.05 -0.01 0.01 0.29 0.19 0.03 0.13SoCal Gas -0.22 0.12 -0.18 -0.14 -0.12 0.16 0.06 -0.10 -0.13NYMEX Basis 0.049 -0.291 0.009 -0.031 -0.051 -0.331 -0.231 -0.071 -0.041 -0.171

NYMEX Basis is the NYMEX Henry Hub/cash basis differential calculated from the near-month settlement of $2.801.

BeNtek CaNadiaN gas storage data For week eNded Jul 8(in Bcf) east west total

Working gas 190.04 494.30 684.34

Weekly Change 8.39 1.24 9.63

% of capacity 72.26% 87.80% 82.85%

Working Gas Jul 10, 2015 133.95 388.84 522.79

HeNry HuB Futures aNd strips

07/04 07/05 07/06 07/07 07/08 Mon tue wed thu FriAug-016 NA 2.764 2.786 2.777 2.801Sep-016 NA 2.758 2.777 2.764 2.788Oct-016 NA 2.802 2.818 2.802 2.827Nov-016 NA 2.955 2.971 2.957 2.990Dec-016 NA 3.206 3.221 3.214 3.251Jan-017 NA 3.341 3.354 3.347 3.384Feb-017 NA 3.332 3.345 3.336 3.370Mar-017 NA 3.284 3.298 3.287 3.318Apr-017 NA 3.043 3.077 3.064 3.082May-017 NA 3.019 3.052 3.041 3.053Jun-017 NA 3.051 3.086 3.079 3.089Jul-017 NA 3.082 3.120 3.113 3.1213/strip NA 2.775 2.794 2.781 2.8056/strip NA 2.971 2.988 2.977 3.0079/strip NA 3.054 3.072 3.061 3.09012/strip NA 3.053 3.075 3.065 3.090

CFtC CoMMitMeNt oF traders report For week eNded July 05 long short net position net position change in % market % market positions positions last week overall positions share share last weekProducers/merchants/processors/users 197,583 185,134 51.63% long 51.61% long -0.14% 31.07% 30.64%Swap dealers 143,642 60,859 70.24% long 71.01% long -1.2% 16.6% 16.55%Money managers 218,023 248,401 53.26% short 52.95% short -2.33% 37.87% 38.18%Other reportables 36,615 141,529 79.45% short 79.98% short -2.61% 14.46% 14.62%

Source: CFTC. For detailed information regarding the categories of traders listed in this table, please see the CFTCs explanatory note at:www.cftc.gov/ucm/groups/public/@commitmentsoftraders/documents/file/disaggregatedcotexplanatorynot.pdf

CANADIAN STORAGE INVENTORIES

Source: Platts Bentek

200

300

400

500

600

700

800

3-Year Avg

20152016

(Bcf)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

($/MMBtu)

2.5

2.7

2.9

3.1

3.3

08-Jul04-Jul28-Jun22-Jun16-Jun10-Jun

3-month12-monthPrompt month

Baker HugHes rig CouNt

week ending 7/8/16 7/1/16 Chg. 7/2/2015

Total US rigs 440 431 +9 862Total US gas rigs 88 89 -1 219Total Canadian rigs 81 76 +5 139

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