(continued on page 3) (continued on page 5)

GAS DAILY News Headlines FERC rejects Jordan Cove, Pacific Connector FERC notes absence of demonstrated need Critics pointed to oversupplied global market Gas Daily Supplements (continued on page 3) Northeast production still growing despite cuts Producers tapping into well inventories Northeast is the only area growing in 2016 (continued on page 5) Coal, gas struggle to balance rising SPP wind Hourly variability increases Negative price instances rise during on-peak hours (continued on page 5) Futures up, cash continues climb from historic low THE MARKET The NYMEX April natural gas futures contract settled 3.4 cents higher Friday to $1.822/MMBtu, marking the sixth day in a row for a higher settle. The contract has climbed nearly 18 cents through the span of this month after hitting a 17-year low of $1.639/MMBtu on March 3. (continued on page 2) SPOT PRICE AND BASIS CHANGES 0.2 0.1 0.0-0.1-0.2-0.3-0.4 ($/MMBtu) AECO-C (NW) Source: Platts Daily spot price change Daily cash basis change Daily spot price change from bidweek Sumas (NW) SoCal Gas (SW) PG&E CG (SW) CIG (NW) Panhandle TX-OK (Mid C) To access the latest issue of the Gas Daily supplements, click below. Gas Daily Market Fundamentals (pdf) Gas Daily Market Fundamentals Data (xls) Gas Daily Monthly Price Guide (pdf) *Links require PMC login. For login help, contact support@platts.com. Waha (SW) Houston Ship (ETX) Henry Hub (SE) Chicago (Mid C) Dominion S Pt (Appal) TX Eastern M-3 (NE) Daily price survey ($/MMBtu) NATIONAL AVERAGE PRICE: 1.600 Trans. date: 3/11 Flow date(s): 3/12 14 midpoint +/- Absolute Common Vol. Deals Northeast Algonquin, city-gates IGBEE21 1.120-0.045 1.050-1.200 1.085-1.160 28 10 Algonquin, receipts IGBDK21 0.920-0.105 0.850-0.925 0.900-0.925 11 3 Dracut, Mass. IGBDW21 - - Iroquois, receipts IGBCR21 1.845 +0.225 1.820-1.890 1.830-1.865 105 20 Iroquois, zone 2 IGBEJ21 1.815 +0.150 1.790-1.900 1.790-1.845 38 15 Niagara IGBCS21 1.150 +0.070 1.150-1.150 1.150-1.150 1 1 Tennessee, z6 (300 leg) del. IGBJC21 1.200 +0.040 1.200-1.200 1.200-1.200 1 1 Tennessee, zone 6 del. IGBEI21 1.190-0.050 1.180-1.230 1.180-1.205 75 15 Tx. Eastern, M-3 IGBEK21 0.855-0.170 0.810-0.900 0.835-0.880 128 32 Transco, zone 5 del. IGBEN21 1.705 +0.000 1.670-1.750 1.685-1.725 233 36 Transco, zone 6 N.Y. IGBEM21 0.875-0.180 0.845-0.920 0.855-0.895 48 18 Transco, zone 6 non-n.y. IGBEL21 0.915-0.165 0.780-1.000 0.860-0.970 142 37 Transco, zone 6 non-n.y. North IGBJS21 0.895-0.140 0.780-1.000 0.840-0.950 114 26 Transco, zone 6-non-N.Y. South IGBJT21 1.000-0.225 1.000-1.000 1.000-1.000 28 11 Northeast regional average IGCAA21 1.235 Appalachia Columbia Gas, App. IGBDE21 1.620 +0.065 1.530-1.655 1.590-1.650 157 36 Columbia Gas, App. non-ipp IGBJU21 - - Dominion, North Point IGBDB21 0.805-0.180 0.770-0.850 0.785-0.825 82 18 Dominion, South Point IGBDC21 0.825-0.175 0.790-0.900 0.800-0.855 231 48 Lebanon Hub IGBFJ21 1.645 +0.030 1.620-1.680 1.630-1.660 123 17 Leidy Hub IGBDD21 - - Millennium, East receipts IGBIW21 0.850-0.115 0.850-0.850 0.850-0.850 1 1 REX, Clarington Ohio IGBGO21 - - Tennessee, zone 4-200 leg IGBJN21 1.000-0.125 0.950-1.100 0.965-1.040 90 19 Tennessee, zone 4-300 leg IGBFL21 0.770-0.145 0.720-0.820 0.745-0.795 41 11 Tennessee, zone 4-313 pool IGCFL21 0.865-0.160 0.830-0.900 0.850-0.885 24 7 Tennessee, zone 4-Ohio IGBHO21 - - Texas Eastern, M-2 receipts IGBJE21 0.795-0.180 0.730-0.860 0.765-0.830 239 42 Transco, Leidy Line receipts IGBIS21 0.805-0.135 0.670-0.860 0.760-0.855 166 28 Appalachia regional average IGDAA21 1.000 Midcontinent ANR, Okla. IGBBY21 1.505 +0.005 1.490-1.520 1.500-1.515 126 19 Enable Gas, East IGBCA21 1.590-0.025 1.540-1.600 1.575-1.600 32 4 NGPL, Amarillo receipt IGBDR21 1.600-0.005 1.585-1.640 1.585-1.615 50 12 NGPL, Midcontinent IGBBZ21 1.530 +0.020 1.500-1.550 1.520-1.545 174 29 Oneok, Okla. IGBCD21 1.475 +0.010 1.465-1.510 1.465-1.485 126 22 Panhandle, Tx.-Okla. IGBCE21 1.510 +0.015 1.490-1.530 1.500-1.520 172 33 Southern Star IGBCF21 1.525 +0.025 1.505-1.540 1.515-1.535 81 15 Tx. Eastern, M-1 24-in. IGBET21 - - Midcontinent regional average IGEAA21 1.535 Upper Midwest Alliance, into interstates IGBDP21 1.750 +0.015 1.700-1.770 1.735-1.770 195 34 ANR, ML 7 IGBDQ21 1.735-0.015 1.730-1.740 1.735-1.740 30 2 Chicago city-gates IGBDX21 1.785 +0.010 1.600-1.930 1.705-1.870 951 137 Chicago-Nicor IGBEX21 1.870 +0.040 1.810-1.930 1.840-1.900 401 48 Chicago-NIPSCO IGBFX21 1.740 +0.025 1.720-1.800 1.720-1.760 323 44 Chicago-Peoples IGBGX21 1.670 +0.010 1.600-1.690 1.650-1.690 99 22 Consumers city-gate IGBDY21 1.760 +0.005 1.730-1.780 1.750-1.775 198 32 Dawn, Ontario IGBCX21 1.900 +0.060 1.880-1.920 1.890-1.910 670 121 Emerson, Viking GL IGBCW21 1.810 +0.035 1.770-1.830 1.795-1.825 223 31 Mich Con city-gate IGBDZ21 1.805 +0.045 1.780-1.830 1.795-1.820 318 46 Northern Bdr., Ventura TP IGBGH21 1.665 +0.000 1.655-1.670 1.660-1.670 33 8 Northern, demarc IGBDV21 1.670-0.010 1.650-1.685 1.660-1.680 320 53 Northern, Ventura IGBDU21 1.665-0.015 1.640-1.675 1.655-1.675 177 27 REX, Zone 3 delivered IGBRO21 1.635 +0.025 1.600-1.680 1.615-1.655 446 76 Upper Midwest regional average IGFAA21 1.745 www.platts.com www.twitter.com/plattsgas NATURAL GAS

The US Energy Information Administration Thursday reported a storage pull of 57 Bcf for last week, in line with the market consensus but substantially below the 174 Bcf withdrawal reported at this time in 2015 and the 118 Bcf five-year-average. The natural gas market continues to march higher in what we see as primarily a technical recovery from the oversold condition of a week ago, Citi energy futures specialist Tim Evans said in a note. According to the National Weather Service, the six- to 10-day outlook is for above-normal temperatures in the eastern half of the country and along the West Coast. Temperatures around the Rocky Mountains in the central part of the county are expected to be below seasonal norms. A modest cooling trend in the temperature outlook has supported this recovery, although we still don t see enough late-season heating demand to produce supportive storage comparisons, Evans said. In that regard, we see the rally as limited. US production declined again Friday to 72.1 Bcf. Although Northeast production did see a slight uptick of 100 MMcf/d, that increase was offset by losses of 200 MMcf in Texas and 100 MMcf in the Southeast. US demand increased 3.4 Bcf Friday to 75.1 Bcf, which was largely driven by colder weather, although demand is still well below 80 Bcf/d, according to data from Platts unit Bentek Energy. The April gas contract traded in a range of $1.792-$1.859/MMBtu. Northeast prices fall ahead of weekend Prices at Texas Eastern Transmission M-3 fell to their lowest level since late December, after giving up 17 cents/mmbtu. Transcontinental Gas Pipe Line Zone 6 New York prices fell 18 cents. According to a notice Transco issued Thursday, the pipeline has limited flexibility to manage imbalances because of mild weather and decreased gas demand forecast to start Friday and continue through next week. As a result, Transco urged shippers to manage system requirements to ensure a concurrent balance of receipts and deliveries daily. Northeast demand is expected to slide to 15.3 Bcf/d by Sunday, nearly 2 Bcf below Friday s level. So far this month demand has averaged 20.67 Bcf/d, down more than 6 Bcf/d from the same period a year ago. Upstream in Appalachia, prices at Dominion Transmission s South Point also fell to its lowest price since late December, shedding nearly 18 cents. In Texas, Houston Ship Channel jumped by a little more than 12 cents. Nearby, Katy Hub rose 9 cents. Texas production fell to 18.9 Bcf/d Friday, down 200 MMcf/d from Thursday. It marked the first time Texas production fell below the 19 Bcf/d mark since mid-january, according to Bentek. The region has been hard hit by heavy rains and flooding in recent days, potentially resulting in weather-related production declines. Assessment Rationale Platts 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 Patrick Badgley at 713-658-3267 or Patrick.Badgley@platts.com Daily price survey ($/MMBtu) Trans. date: 3/11 Flow date(s): 3/12 14 East Texas Midpoint +/- Absolute Common Vol. Deals Agua Dulce Hub IGBAV21 1.720 +0.100 1.720-1.720 1.720-1.720 10 1 Carthage Hub IGBAF21 1.680 +0.035 1.660-1.700 1.670-1.690 60 10 Florida Gas, zone 1 IGBAW21 1.715 +0.045 1.710-1.740 1.710-1.725 52 2 Houston Ship Channel IGBAP21 1.725 +0.125 1.700-1.750 1.715-1.740 80 11 Katy IGBAQ21 1.775 +0.090 1.730-1.820 1.755-1.800 316 44 NGPL, STX IGBAZ21 1.630 +0.000 1.630-1.630 1.630-1.630 20 2 NGPL, Texok zone IGBAL21 1.630 +0.020 1.580-1.690 1.605-1.660 286 41 Tennessee, zone 0 IGBBA21 1.695 +0.035 1.680-1.720 1.685-1.705 104 15 Tx. Eastern, ETX IGBAN21 - - Tx. Eastern, STX IGBBB21 1.740 +0.080 1.700-1.760 1.725-1.755 188 30 Transco, zone 1 IGBBC21 1.685 +0.030 1.660-1.690 1.680-1.690 70 24 Transco, zone 2 IGBBU21 1.675 +0.005 1.655-1.710 1.660-1.690 27 6 East Texas regional average IGGAA21 1.695 Louisiana/Southeast ANR, La. IGBBF21 1.650 +0.015 1.640-1.660 1.645-1.655 104 19 Columbia Gulf, La. IGBBG21 1.690 +0.065 1.600-1.750 1.655-1.730 277 32 Columbia Gulf, mainline IGBBH21 1.655 +0.045 1.560-1.725 1.615-1.695 268 46 Florida city-gates IGBED21 2.000 +0.230 2.000-2.000 2.000-2.000 15 1 Florida Gas, zone 2 IGBBJ21 1.745 +0.075 1.720-1.760 1.735-1.755 148 5 Florida Gas, zone 3 IGBBK21 1.755 +0.030 1.730-1.790 1.740-1.770 315 26 Henry Hub IGBBL21 1.720 +0.025 1.670-1.775 1.695-1.745 184 31 Southern Natural, La. IGBBO21 1.690 +0.035 1.660-1.740 1.670-1.710 163 30 Tennessee, 500 Leg IGBBP21 1.670 +0.020 1.615-1.700 1.650-1.690 184 39 Tennessee, 800 Leg IGBBQ21 1.675 +0.025 1.600-1.720 1.645-1.705 390 65 Tx. Eastern, ELA IGBBS21 1.700 +0.060 1.600-1.740 1.665-1.735 69 15 Tx. Eastern, M-1 30-in. IGBDI21 1.650 +0.025 1.645-1.655 1.650-1.655 10 6 Tx. Eastern, WLA IGBBR21 1.720 +0.070 1.680-1.745 1.705-1.735 56 7 Tx. Gas, zone 1 IGBAO21 1.650 +0.035 1.620-1.660 1.640-1.660 273 36 Tx. Gas, zone SL IGBBT21 - - Transco, zone 3 IGBBV21 1.685 +0.020 1.660-1.710 1.675-1.700 305 42 Transco, zone 4 IGBDJ21 1.705 +0.020 1.660-1.750 1.685-1.730 730 77 Trunkline, ELA IGBBX21 1.655 +0.105 1.650-1.660 1.655-1.660 7 2 Trunkline, WLA IGBBW21 - - Trunkline, zone 1A IGBGF21 1.640 +0.045 1.630-1.650 1.635-1.645 20 6 Louisian/Southeast regional average IGHAA21 1.705 Rockies/Northwest Cheyenne Hub IGBCO21 1.490 +0.015 1.470-1.510 1.480-1.500 114 18 CIG, Rockies IGBCK21 1.450 +0.005 1.430-1.470 1.440-1.460 85 15 GTN, Kingsgate IGBCY21 1.240-0.005 1.210-1.265 1.225-1.255 179 21 Kern River, Opal IGBCL21 1.475 +0.005 1.450-1.520 1.460-1.495 168 27 NW, Can. bdr. (Sumas) IGBCT21 1.300-0.035 1.250-1.350 1.275-1.325 191 42 NW, s. of Green River IGBCQ21 1.440 +0.030 1.410-1.450 1.430-1.450 68 11 NW, Wyo. Pool IGBCP21 1.430 +0.015 1.410-1.520 1.410-1.460 66 10 PG&E, Malin IGBDO21 1.550 +0.010 1.520-1.570 1.540-1.565 308 36 Questar, Rockies IGBCN21 1.420-0.015 1.420-1.420 1.420-1.420 4 1 Stanfield, Ore. IGBCM21 1.375-0.005 1.365-1.390 1.370-1.380 194 35 TCPL Alberta, AECO-C* IGBCU21 1.345 +0.080 1.300-1.390 1.325-1.370 916 91 Westcoast, station 2* IGBCZ21 1.000 +0.045 0.990-1.025 0.990-1.010 61 18 White River Hub IGBGL21 1.495 +0.040 1.460-1.520 1.480-1.510 117 17 Rockies/Northwest regional average IGIAA21 1.350 Southwest El Paso, Bondad IGBCG21 1.470 +0.005 1.450-1.500 1.460-1.485 73 11 El Paso, Permian IGBAB21 1.510 +0.020 1.455-1.550 1.485-1.535 264 46 El Paso, San Juan IGBCH21 1.480 +0.015 1.450-1.510 1.465-1.495 136 18 El Paso, South Mainline IGBFR21 1.545 +0.005 1.500-1.620 1.515-1.575 63 7 Kern River, delivered IGBES21 1.530-0.015 1.485-1.555 1.515-1.550 228 26 PG&E city-gate IGBEB21 1.915 +0.020 1.900-1.930 1.910-1.925 682 76 PG&E, South IGBDM21 1.555 +0.010 1.535-1.575 1.545-1.565 64 11 SoCal Gas IGBDL21 1.540-0.005 1.500-1.560 1.525-1.555 92 18 SoCal Gas, city-gate IGBGG21 1.700-0.015 1.650-1.740 1.680-1.725 223 32 Transwestern, Permian IGBAE21 1.490-0.010 1.440-1.540 1.465-1.515 100 20 Transwestern, San Juan IGBGK21 1.465 +0.005 1.450-1.470 1.460-1.470 30 5 Waha IGBAD21 1.585 +0.025 1.500-1.650 1.550-1.625 372 46 Southwest regional average IGJAA21 1.565 *Price in C$ per gj; C$1=US$0.7567; Volume in 000 MMBtu/day. Symbols represent gas flow date. 2

Midcontinent prices rise on storage restrictions Bentek Energy predicts market-area demand will fall over the weekend and through Monday. Demand currently is at the 11.2-Bcf level and is expected to fall to 8.7 Bcf Monday. Weather forecasts high temperatures to reach the upper 50s in both Detroit and Chicago, about 14 degrees above seasonal norms. At the Chicago city-gates, storage restrictions resulted in increases that were most pronounced at Nicor, where prices rose about 4 cents. On March 5, Nicor said it would halt interruptible injection services until further notice. Prices at Peoples and NIPSCO also picked up 1 cent-2 cents but remained more than 10 cents below the Nicor spot price. High temperatures in Oklahoma City are slated to continue hovering in the mid-60s Saturday and shooting higher to the low-80s by Monday, well above seasonal averages. Natural Gas Pipeline Co. of America s Midcontinent and Texok zones both increased 2 cents. Back on March 9, NGPL enacted restrictions that are still in place on their Amarillo System stating: Natural will require in-path transportation for NSS storage injections on the Amarillo System. ITS/ AOR and Secondary out-of-path firm transportation associated with NSS injections will not be scheduled. Northwest cash mixed Weather outlooks within the Northwest were also mixed, with Denver expecting highs around 70 Saturday through Monday, about 14 degrees above normal, and Seattle forecast to see highs around 50, a few degrees below the seasonal average. Opal, Cheyenne Hub and Colorado Interstate Gas-Rockies rose 1 cent each Southwest prices were mixed with only small movements as demand was expected to inch upward over the weekend. Bentek projected total West demand would average 9.7 Bcf/d Saturday through Monday, up from Friday s 9.6 Bcf/d. Market Staff Reports FERC rejects Jordan Cove, Pacific Connector In a surprising move, the US Federal Energy Regulatory Commission late Friday rejected the Jordan Cove LNG export project and related Pacific Connector pipeline meant to feed gas to the facility. Among other things, FERC determined that Pacific Connector had failed to demonstrate a need for the project; it had no precedent agreements in hand and had not conducted an open season. And without a pipeline supplying natural gas, FERC found it would be impossible for the Jordan Cove LNG terminal to operate. It denied approval for the terminal, saying it can provide no benefit to counterbalance any of the impacts. The commission has not previously authorized LNG export terminal facilities without a known transportation source of natural gas, said the March 11 order. The commission highlighted comments from landowners in the record asking it to balance the failure to provide evidence of market demand and the failure to acquire easements along the right-of-way against impacts to landowners who would face eminent domain actions if the commission issued a certificate. Weekly weighted average prices Northeast 03/05-03/11 wkly total 2016 -/+ High Low Volumes Algonquin, city-gates IGBEE04 1.589-0.897 1.689 1.473 322 Algonquin, receipts IGBDK04 0.940-0.601 0.950 0.866 119 Dracut, Mass. IGBDW04 0 Iroquois, receipts IGBCR04 1.686-0.208 1.771 1.646 931 Iroquois, zone 2 IGBEJ04 1.746-0.289 1.861 1.681 383 Niagara IGBCS04 1.255-0.179 1.272 1.246 233 Tennessee, z6 (300 leg) del. IGBJC04 1.160-0.907 1.160 1.160 2 Tennessee, zone 6 delivered IGBEI04 1.610-0.863 1.679 1.523 486 Texas Eastern, M-3 IGBEK04 0.969-0.155 1.023 0.931 1523 Transco, zone 5 delivered IGBEN04 1.574-0.088 1.633 1.370 1341 Transco, zone 6 N.Y. IGBEM04 1.106-0.278 1.147 1.066 283 Transco, zone 6 non-n.y. IGBEL04 1.141-0.233 1.389 1.051 1458 Transco, zone 6 non-n.y. North IGBJS04 1.127-0.245 1.241 1.051 1337 Transco, zone 6 non-n.y. South IGBJT04 1.325-0.014 1.389 1.247 122 Appalachia Columbia Gas, Appalachia IGBDE04 1.434-0.075 1.461 1.414 563 Columbia Gas, Appalachia non-ipp IGBJU04 1.219-0.197 1.256 1.160 112 Dominion, North Point IGBDB04 0.911-0.080 0.933 0.889 700 Dominion, South Point IGBDC04 0.917-0.096 0.958 0.871 1588 Lebanon Hub IGBFJ04 1.473-0.096 1.486 1.459 427 Leidy Hub IGBDD04 0 Millennium, East receipts IGBIS04 0.921-0.091 0.975 0.907 202 REX, Clarington Ohio IGBGO04 0 Tennessee, zone 4-200 leg IGBJN04 1.104-0.146 1.146 1.060 659 Tennessee, zone 4-300 leg IGBFL04 0.882-0.102 0.919 0.846 408 Tennessee, zone 4-313 pool IGCFL04 0.976-0.093 1.061 0.961 148 Tennessee, zone 4-Ohio IGBHO04 0 Texas Eastern, M-2 receipts IGBJE04 0.893-0.115 0.921 0.844 2025 Transco, Leidy Line receipts IGBIW04 0.894-0.098 0.958 0.844 1587 Midcontinent ANR, Okla. IGBBY04 1.379-0.074 1.413 1.354 909 Enable Gas, East IGBCA04 1.451-0.048 1.486 1.444 433 NGPL, Amarillo receipt IGBDR04 1.450-0.076 1.481 1.418 237 NGPL, Midcontinent IGBBZ04 1.381-0.078 1.409 1.342 1547 Oneok, Okla. IGBCD04 1.332-0.059 1.383 1.306 646 Panhandle, Tx.-Okla. IGBCE04 1.378-0.056 1.411 1.336 1237 Southern Star, Tx.-Okla.-Kan. IGBCF04 1.362-0.055 1.388 1.349 612 Texas Eastern M-1 24-inch IGBET04 0 Upper Midwest Alliance, into interstates IGBDP04 1.636-0.072 1.682 1.599 1793 ANR, ML 7 IGBDQ04 1.629-0.061 1.637 1.623 121 Chicago city-gates IGBDX04 1.663-0.043 1.769 1.456 5469 Chicago-Nicor IGBEX04 1.737 0.024 1.769 1.648 2793 Chicago-NIPSCO IGBFX04 1.594-0.101 1.664 1.559 1705 Chicago-Peoples IGBGX04 1.535-0.140 1.587 1.457 522 Consumers Energy city-gate IGBDY04 1.665-0.041 1.681 1.647 1172 Dawn, Ontario IGBCX04 1.746-0.011 1.790 1.719 4253 Emerson, Viking GL IGBCW04 1.670-0.056 1.724 1.628 1409 Mich Con city-gate IGBDZ04 1.680-0.039 1.710 1.634 2626 Northern Border, Ventura TP IGBGH04 1.520-0.121 1.536 1.506 350 Northern, demarc IGBDV04 1.527-0.101 1.553 1.504 1317 Northern, Ventura IGBDU04 1.520-0.112 1.536 1.499 1148 REX, Zone 3 delivered IGBRO04 1.473-0.094 1.505 1.454 2126 East Texas Agua Dulce Hub IGBAV04 1.565-0.024 1.565 1.565 7 Carthage Hub IGBAF04 1.488-0.058 1.504 1.471 327 Florida Gas, zone 1 IGBAW04 1.670 0.092 1.670 1.670 6 Houston Ship Channel IGBAP04 1.491-0.087 1.512 1.479 279 Katy IGBAQ04 1.526-0.043 1.559 1.492 5411 NGPL, STX IGBAZ04 1.469-0.080 1.494 1.457 165 NGPL, Texok zone IGBAL04 1.474-0.062 1.496 1.441 1985 3

FERC notes absence of demonstrated need Issuing a certificate in this case would allow Pacific Connector to move forward with eminent domain proceedings in what we find to be the absence of a demonstrated need for the pipeline, the commission concluded. We find the generalized allegations of need proffered by Pacific Connector do not outweigh the potential adverse impact on landowners and communities, FERC said. The companies failed to demonstrate demand to back up the claim that the pipeline would benefit the public by delivering gas supply from the Rocky Mountains and Canada to the Jordan Cove LNG terminal and by adding a source of gas supply to southern Oregon, FERC said. In rejecting the projects, FERC noted that it had never previously found a proposed pipeline to be required by public convenience and necessity on the basis of US Department of Energy finding that LNG imports or exports are in the public interest, nor solely on the fact that a firm was unlikely to proceed with construction in the absence of a market, as it suggested was requested here. Jordan Cove filed an application (CP13-483) with FERC in May 2013 to build liquefaction and export facilities, including four liquefaction trains that could each process roughly 1.5 million mt/year; two 160,000 cu m (3.44 Bcf) full-containment storage tanks; and a new marine slip with two berths. The export terminal, estimated to cost $5.3 billion, would be capable of liquefying the LNG equivalent of 900 MMcf/d of gas. Pacific Connector (CP13-492) in June 2013 applied to build a 232-mile pipeline to feed gas to the facility. The 1.06-million Dt/d pipeline would connect with Ruby Pipeline and Gas Transmission Northwest near Malin, Oregon, and run to the proposed export project in Coos County. The $1.74 billion project would also include a 41,000 horsepower compressor station in Klamath County, as well as a number of meter stations. Critics pointed to oversupplied global market In December, critics of the Jordan Cove project asked FERC to consider growing analyses suggesting that the global LNG market is oversupplied already in weighing the project application. Citizens Against LNG in a December 12 letter told the commission that multiple financial and gas industry reports are stating that projects like Jordan Cove are no longer viable due to a glut of LNG in the market that is predicted to be in effect for many years to come. Noting that Jordan Cove and Pacific Connector had recently informed FERC that their project did not have signed contracts, the citizens group said, this is all the FERC should need in order to deny Jordan Cove a Site Certificate. The project application traveled a bumpy road at FERC, which twice pushed back the target date for final action. Commission staff in February 2015 pushed the authorization decision from May to September as it sought more information to complete its review. In June staff revised the schedule again, setting December 29 as the federal authorization decision deadline for the LNG project and pipeline. The commission on several occasions had asked project sponsors Weekly weighted average prices Tennessee, zone 0 IGBBA04 1.494-0.067 1.511 1.474 1357 Texas Eastern, ETX IGBAN04 1.516-0.029 1.518 1.515 4 Texas Eastern, STX IGBBB04 1.508-0.070 1.523 1.496 1004 Transco, zone 1 IGBBC04 1.508-0.061 1.520 1.489 331 Transco, zone 2 IGBBU04 1.509-0.062 1.515 1.504 114 Louisiana/Southeast ANR, La. IGBBF04 1.496-0.069 1.516 1.467 636 Columbia Gulf, La. IGBBG04 1.499-0.069 1.517 1.477 788 Columbia Gulf, mainline IGBBH04 1.481-0.072 1.516 1.451 1691 Florida city-gates IGBED04 1.704-0.041 1.715 1.689 58 Florida Gas, zone 2 IGBBJ04 1.526-0.058 1.543 1.514 720 Florida Gas, zone 3 IGBBK04 1.565-0.050 1.586 1.539 1984 Henry Hub IGBBL04 1.543-0.073 1.572 1.519 1233 Southern Natural, La. IGBBO04 1.522-0.058 1.556 1.504 1561 Tennessee, La., 500 Leg IGBBP04 1.521-0.065 1.543 1.496 1180 Tennessee, La., 800 Leg IGBBQ04 1.501-0.063 1.530 1.477 2175 Texas Eastern, ELA IGBBS04 1.508-0.055 1.521 1.493 847 Texas Eastern, M-1 30-inch (Kosi) IGBDI04 1.474-0.099 1.485 1.460 14 Texas Eastern, WLA IGBBR04 1.502-0.067 1.513 1.494 700 Texas Gas, zone 1 IGBAO04 1.477-0.075 1.502 1.454 1243 Texas Gas, zone SL IGBBT04 1.470-0.060 1.470 1.470 3 Transco, zone 3 IGBBV04 1.521-0.064 1.549 1.489 1324 Transco, zone 4 IGBDJ04 1.545-0.064 1.571 1.521 3909 Trunkline, ELA IGBBX04 1.483-0.070 1.490 1.458 54 Trunkline, WLA IGBBW04 1.575-0.205 1.575 1.575 2 Trunkline, Zone 1A IGBGF04 1.441-0.103 1.485 1.417 798 Rockies/Northwest Cheyenne Hub IGBCO04 1.355-0.073 1.376 1.324 1041 CIG, Rocky Mountains IGBCK04 1.309-0.062 1.328 1.294 413 GTN, Kingsgate IGBCY04 1.177-0.059 1.190 1.153 693 Kern River, Opal plant IGBCL04 1.364-0.064 1.386 1.341 2673 Northwest, Can. bdr. (Sumas) IGBCT04 1.282-0.069 1.295 1.263 1859 Northwest, s. of Green River IGBCQ04 1.302-0.092 1.314 1.296 208 Northwest, Wyo. Pool IGBCP04 1.314-0.102 1.374 1.294 241 PG&E, Malin IGBDO04 1.434-0.047 1.444 1.416 1668 Questar, Rocky Mountains IGBCN04 1.384-0.017 1.385 1.380 24 Stanfield, Ore. IGBCM04 1.293-0.094 1.316 1.283 837 TCPL Alberta, AECO-C* IGBCU04 1.201-0.075 1.226 1.189 6004 Westcoast, station 2* IGBCZ04 0.897-0.053 0.944 0.860 963 White River Hub IGBGL04 1.345-0.076 1.370 1.324 617 Southwest El Paso, Bondad IGBCG04 1.347-0.081 1.387 1.317 853 El Paso, Permian Basin IGBAB04 1.376-0.070 1.409 1.349 2361 El Paso, San Juan Basin IGBCH04 1.366-0.075 1.416 1.336 1284 El Paso, South Mainline IGBFR04 1.429-0.089 1.455 1.410 608 Kern River, delivered IGBES04 1.440-0.071 1.474 1.405 2126 PG&E city-gate IGBEB04 1.799-0.012 1.818 1.781 3859 PG&E, South IGBDM04 1.436-0.073 1.458 1.415 480 SoCal Gas IGBDL04 1.439-0.072 1.470 1.391 1118 SoCal Gas, city-gate IGBGG04 1.557-0.076 1.601 1.529 2919 Transwestern, Permian Basin IGBAE04 1.354-0.066 1.381 1.330 566 Transwestern, San Juan IGBGK04 1.372-0.083 1.397 1.331 253 Waha IGBAD04 1.412-0.060 1.454 1.345 1797 *NOTE: Price in C$ per gj Baker Hughes rig count 03/05-03/11 wkly total 2016 -/+ High Low Volumes Week ending 3/11/16 3/4/16 Chg. 3/13/15 Total US rigs 480 489-9 1,125 Total US gas rigs 94 97-3 257 Total Canadian rigs 98 129-31 220 4

for updates on contract talks. FERC previously granted authorization for Jordan Cove to build an LNG import facility, but that permit was vacated in April 2012 after the company made clear that it like so many other prospective project sponsors had shifted its efforts to exporting LNG to take advantage of surging US shale gas production. The commission said its rejection was without prejudice to Jordan Cove and/or Pacific Connector submitting a new application... should the companies show a market need for these services in the future. Maya Weber, Chris Newkumet Northeast production still growing despite cuts ANALYSIS Northeast producers are expected to cut capital expenditures on drilling this year by 40%, which is clearly reflected in the active rig count decline to 47 rigs from 95 at the same time last year. Despite these reductions, however, production is still expected to increase 13% in 2016, driven by the large well inventory in place. Antero Resources, a major Northeast producer, expects to grow its production 15% in 2016 despite a 23% capital budget cut. Cabot Oil & Gas, another large regional producer, reported production growth estimates of 2-7% with a year-over-year capex cut of 58%. Other producers have reported similar spending cuts and production expectations. Northeast Producers Producer Capex production Antero 23% 15% Cabot 58% 2%-7% CHK 57% 0-5% EQT 44% 18% Range 43% 8%-10% Rice 15% 30% Notes: Values are based on 2016 producer guidance estimates Values reflect producer s total capex and total production All percentages are based on year-over-year averages changes from 2015 to 2016 Producers already are tapping into their well inventories in the region. October 2015 appears to have been the starting point for inventory reductions in the Northeast. That is when the number of wells coming online began to exceed the number being backlogged, according to Platts Bentek data. At the peak last October, well inventories reaching 2,697. NORTHEAST WELL INVENTORY (number of wells) 1200 PA South Dry PA Central Dry NE PA Dry 900 Total (right axis) Ohio PA SW Wet (total) 2800 2600 Between October and December, however, there was a decline of about 411 wells, bringing the Northeast well inventory count to 2,286 wells. This well inventory drop supports production estimates by producers. Additional wells from inventory will be needed to supplement current drilling activity if Northeast production is expected to grow with lower capital investment. Northeast Regional Breakdown of Well Inventory (number of wells) ne PA Dry PA Central Dry PA South Dry PA SW Wet Ohio Total Oct-15 987 223 364 539 584 2,697 Dec-15 858 213 262 425 528 2,286 Oct to Dec -129-10 -102-114 -56-411 *data used in feature (only used timeframes referenced Source: Platts Bentek The Northeast is the only area in the US expected to maintain yearover-year growth in 2016. Before the inventory is depleted in 2017, Northeast producers will have to ramp up drilling to avoid a severe production decline. With gas prices at extreme lows and storage levels nearly 60% higher than last year, producers will be hardpressed to resume a faster drilling pace entering 2017. Matt Andre Coal, gas struggle to balance rising SPP wind ANALYSIS Surging wind generation and a coal-heavy generation fleet in the Southwest Power Pool have contributed to an unusual increase in negative on-peak power prices. Wind generation in SPP set two consecutive records for market share March 6 and March 7. The latter record was set shortly after 1am CST as market share topped 45.1% with instantaneous wind output peaking at 9,450 MW. The market share gains come as SPP reported at the beginning of the year that its territory included 156 wind facilities totaling 12,400 MW of interconnected capacity. By the end of the year, the grid operator expects to have a total of 16,960 MW of wind online. In 2015, average market share for wind generation in SPP was 13.8%. Year-to-date average wind market share in SPP is about 18.5%, up 6.1 percentage points from the same period last year and 7.3 percentage points from 2014. Hourly variability increases, albeit slower than overall output As expected with the increasing presence of an intermittent resource like wind, variability, measured by hourly standard deviation of output, has increased significantly. The standard deviation of hourly wind output in February was 2,541 600 2400 PLATTS GAS IS ON TWITTER 300 2200 FOR UP-to-THE-MINUTE GAS NEWS AND INFORMATION FROM PLATTS 0 Jun-15 Jul-15 Source: Platts Bentek Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 2000 Follow us on twitter.com/plattsgas 5

SPP WIND OUTPUT AND VARIABILITY (MWh) (%) 7000 70 6000 5000 4000 3000 2000 1000 0 Feb-11 Source: SPP MWh, up 30% from February 2015 and 62% higher than February 2014. However, despite growing variability in output on a MWh basis, the relative standard deviation, defined as the ratio of wind s hourly standard deviation to average hourly generation, has decreased sharply since June 2015. This stability is a result of wind assets in SPP becoming more geographically diverse, allowing the variability to net out over a larger area. Negative price instances rise during on-peak hours So far this year, instances of negative prices have been more prevalent during on-peak hours despite wind output s typical peak in the evening. Across all off-peak hours, the frequency of negative prices is up 18% year over year so far in 2016. Meanwhile, on-peak at SPP North has seen negative pricing in the real-time market jump 270% during January and February compared to last year. NEGATIVE 5-MINUTE PRICES AT SPP NORTH (JAN-FEB '16) (Count) 60 50 40 30 20 10 0 1 Source: SPP 0 Dec-11 Oct-12 Aug-13 Jun-14 Apr-15 Feb-16 Hourly standard dev. (left axis) Average hourly output (left axis) Relative standard dev. (right axis) 2014 3 5 2015 7 2016 9 11 More negative prices suggest need for balancing assets The rise is in negative prices is at least partly because of coal s inability to quickly balance changes in load. That fuel accounts for nearly 50% of total generation so far this year. High and steady wind output during off-peak hours is shifting a higher proportion of coal generation toward on-peak hours. The most significant increase in negative pricing, from 10am to 3pm, coincides with the mid-day ramp down in load. With coal being the majority fuel, it sees the steepest decline in output. Meanwhile, gas generation in SPP has stayed relatively flat despite 13 15 17 19 21 23 60 50 40 30 20 10 increased competitiveness with coal amid record low gas prices. Average daily output for gas-fueled plants is only up 1% year to date. Meanwhile market share has declined 0.5%. Additionally, gas has not seen the corresponding increase in dispatch variability that would be expected with surging wind. AVERAGE HOURLY COAL GENERATION (JAN-FEB) (MW) 20000 2014 18000 16000 14000 12000 10000 Source: SPP 1 3 2015 5 7 2016 9 Wind s higher market share has challenged other resources, such as coal and gas, to effectively balance supply and demand during periods of large changes in load. As recently as last November, the hourly variability in wind generation equated to 10% of average hourly load. In February, the ratio declined to a still significant 9.1%. Jonathan Nelson Cabot liable in groundwater contamination case In a case closely watched by the oil and gas industry and by environmental organizations alike, a federal jury Thursday ordered Cabot Oil and Gas to pay a pair of Pennsylvania families more than $4.2 million for contaminating the landowners water wells with methane due to negligence in the drilling and completion of two nearby gas wells. The jury ordered Cabot to pay $1.3 million each to husband and wife Nolen and Monica Ely, as well as $50,000 to each of the couple s three children, for inconvenience and discomfort and creating a private nuisance. The verdict also called for Cabot to pay $720,000 each to Raymond and Victoria Hubert and $50,000 to their daughter Hope. The trial took place in a US District Court in Scranton. Cabot now has 28 days to file a motion to reverse the verdict, which Cabot said it plans to do. After the verdict was announced Cabot spokesman George Stark said the company would file motions in an attempt to overturn the verdict and get a new trial. Cabot argued during the trial that there was no physical evidence linking fracking operations to the contaminated water wells, and such contamination likely occurred naturally. It s a case more than six years in the making, stemming back to 2009 and the Dimock Township, a rural community in northeast Pennsylvania with a population of fewer than 1,500. The plaintiffs claimed a neighboring pair of improperly drilled and completed gas wells led to dangerous levels of methane entering the aquifer and water wells located well above the Marcellus Shale. Originally including more than 10 families of plaintiffs, all but the Elys and Huberts settled with Cabot back in 2012. 11 13 15 17 19 21 23 6

The plaintiffs attorneys argued that through an improper completion, Cabot made the local water supply undrinkable, making it brown, slimy and containing methane beyond acceptable contamination levels. State had fined company $4.1 million in 2010 The Pennsylvania Department of Environmental Protection fined Cabot $4.1 million in December 2010 for improperly casing its wells and allowing methane to migrate into nearby water wells. Cabot accepted the settlement with state regulators, but admitted no wrongdoing. Methane in Dimock water wells has been a historic fact, and the area is rife with pockets of shallow gas, Cabot has said. Although there have been numerous legal settlements over alleged water contamination by way of improper drilling and completion techniques, this is possibly the first time a jury found in favor of the plaintiff in such a case. Dimock has long been one of the most significant flashpoints in the ongoing debate on whether hydraulic fracturing or fracking has ever resulted in groundwater pollution. The US Environmental Protection Agency, which has come under fire from the oil and gas industry for its attempts to establish such a link, had briefly waded into the Dimock controversy. EPA found no well contamination In July 2012, the EPA concluded that water from private drinking water wells Dimock did not contain elevated levels of contaminants requiring agency action (GD 7/26/12). EPA had stepped into the case earlier in 2012, saying test data from Cabot and the Pennsylvania Department of Environmental Protection indicated that the wells had the potential for unacceptable levels of pollutants. EPA s decision to remove itself from the investigation was widely criticized at the time by the environmental community. In a similar case in 2014, a Dallas jury ordered Aruba Petroleum to pay almost $3 million to a Texas family. The plaintiffs attorney in that case used the same private nuisance argument. However, instead of citing groundwater pollution, the plaintiffs in that case said the nuisance occurred due to air contamination from nearby gas wells. Brandon Evans Canadian producers OK climate deal Oil and gas producers in Canada seem to be more accepting of their government s position on climate change than their counterparts in the US, judging from the respective reactions of industry associations in the two countries to the joint statement that President Barack Obama and Canadian Prime Minister Justin Trudeau issued on the subject Thursday in Washington. In that statement, the government of Canada formally backed a US commitment to cut methane emissions from oil and gas activities by at least 40% from 2012 levels by 2025. While associations representing the US oil and gas industry immediately criticized the agreement saying the Obama administration s climate plan would impose unnecessary and burdensome regulations on the industry the association representing Canadian energy producers took a more moderate tone in its response to the joint statement. The methane reduction targets contained in the statement for Canada as a whole largely reflect those that the country s oil- and gasproducing provinces already have been working to hammer out in the cooperation with the energy industry itself, Alex Ferguson, vice president of policy and performance for the Canadian Association of Petroleum Producers, said in an interview from Washington on Thursday. We have been working with the provinces and other stakeholders at the table, Ferguson said. I m comfortable that our federal government is not going to work against the provinces but will work with the provinces. Canadian federal officials had been working on a climate strategy even before the current Liberal government under Trudeau swept into power last October, Ferguson said. Those early discussions, which go back more than a year, also talked about aligning with the US on methane emissions reductions, on regulatory frameworks, he said. Regulation of existing facilities a potential issue The previous announcement we saw a year or so ago in Canada was around how the feds would come in and regulate new facilities and how the legacy assets, the existing facilities, would be turned over to the provinces to figure out what s the best model for that, Ferguson said. However, the joint statement released Thursday signals a key difference from the policy of the previous Canadian government; in that Trudeau s government promised to include regulation of emissions from existing facilities, when it publishes an initial draft of proposed regulations by early next year. That created a little bit of a stir for us, because CAPP had already been working with the western Canadian provinces on crafting emissions reduction regulations for the existing facilities, Ferguson said. Does this mean there s going to be new model that s going to supersede the work we ve been doing with the provinces on this, or is this an opportunity for our federal government to work with the provinces? he asked. I have some comfort that this is a model for the existing facilities where the federal government will work with the provinces and that s good for us. Ferguson also expressed some hope echoed by his counterparts south of the international border that whatever new emissions regulations are devised should be written in such a way as to not discourage oil and gas development in the country. The industry right now and I don t care if you re in the US or Canada is pretty concerned with the economics that are driving us. Current conditions are pretty close, so any additional cost burden we re very concerned about, he said. We want to be able to achieve emissions reductions; we re onboard with that, but we need to do them in a way that we can afford to do it, that makes sense not just for our sector, but for the Canadian economy, because we re a big part of the Canadian economy. As to whether Canada should align its climate change goals with the US, Ferguson said Canadian producers are on board with the 7

idea, up to a point. Sometimes, there s been a little bit of track record in the US of pretty strong aspirations that have been stated in the climate area and then things kind of getting stuck and not proceeding, he said. He noted that the Obama administration s Clean Power Plan seems like it s caught in the courts, as a result of challenges by energy-producing states. Alignment is great, but let s make sure we do what s right for our operators and our resources in Canada and do what we can to align with our partner across the board, instead of saying we re going to align with what they say and then we ll figure out what that means for us, he said. US energy groups united in opposition to emissions targets Meanwhile, in contrast to CAPP s somewhat nuanced response to the Obama/Trudeau joint statement, groups that represent the US oil and gas industry were united in the opposition to the announced emission reduction goals. Additional regulations on methane by the administration could discourage the shale energy revolution that has helped America lead the world in reducing emissions while significantly lowering the costs of energy to consumers, Kyle Isakower, American Petroleum Institute s vice president for regulatory and economic policy, said in a statement Thursday. The administration is catering to environmental extremists at the expense of American consumers, Isakower said. President Obama s announcement of further punitive measures on the oil and natural gas industry, which has already voluntarily decreased methane emissions by 21% even as natural gas production has soured 47%, continues policies that are counterproductive to his stated climate change goals, said Kathleen Sgamma, vice president of government and public affairs, of the Western Energy Alliance. Our industry has delivered 59% more climate change benefits, through increased natural gas electricity generation, than wind and solar combined, she said in a statement. This new, aggressive proposal threatens about 20% of America s oil production and 13% of its natural gas production from America s smallest oil and natural gas wells, Independent Petroleum Association of America Executive Vice President Lee Fuller said in a statement. There is no concrete data that justifies the risks of shutting down significant amounts of American oil and natural gas production. Jim Magill Warren warns bankruptcy filing could be near Denver-based exploration-and-production company Warren Resources warned investors Thursday that it might be forced to seek protection of the bankruptcy court, largely as a result of continued low oil and gas prices. We caution investors that we cannot provide any assurance that Warren will be able to achieve a restructuring of its debt outside of a bankruptcy proceeding, Warren s President and CEO James A. Watt said in a statement. In light of prevailing oil prices and the necessity of a debt restructuring, Warren elected to not make the approximately $7.5 million interest payment due February 1, 2016 on its unsecured senior notes, the company said. It added that the applicable 30-day grace period for making the interest payment had expired, and consequently an event of default under the indenture governing such notes has occurred and is continuing. Watt said Warren has made progress in its discussions with its lenders and we are hopeful that all our creditors will cooperate in reaching a viable solution addressing the reality of low oil prices and our realistic debt service capacity. Stock can trade on Nasdaq through June 20 In a bit of good news, the company said that on March 7, Warren received a decision letter from the Nasdaq Hearings Panel that Warren s common stock would be permitted to continue to trade on the Nasdaq Global Market through June 20. The continued listing of Warren s common stock is contingent on Warren providing the panel with an update regarding its restructuring efforts on or before April 20, and completing a reverse stock split that results in a minimum closing bid price of $1.00 for a minimum of 10 consecutive trading days prior to June 20. Last month, Warren announced that in 2015, the company produced 28 Bcf (76 MMcf/d) of gas and 980,000 barrels (2,684 b/d) of oil and had estimated net proved reserves of 241.3 Bcfe, which included 12 million barrels of oil and 163.7 Bcf of gas. Jim Magill Rig count, production fall in Bakken For the second consecutive month, gas production in North Dakota s Bakken Shale fell. After hitting an all-time high of 1.676 Bcf/d in November, production fell slightly to 1.671 Bcf/d in December and dropped further to 1.638 Bcf/d in January, according to a report released Friday by North Dakota s Industrial Commission. Rig count also plunged as producers in the region continue to scale back operations as they wait for oil to reach a more sustainable price. Rig count has fallen for the fourth straight month, hitting a nineyear low this month. The rig count as of Friday was 33, the lowest posted since March 2007. As recently as December, 64 rigs were active across the Bakken, according to the report. The drilling rig count fell 12 from December to January and the same amount from January to February, and again into this month, said Lynn Helms, director of North Dakota s Department of Mineral Resources. Operators are now even more committed to running fewer rigs as oil prices remain at very low levels Oil price weakness is now anticipated to last into at least the third quarter of this year and is the main reason for the continued slow-down. DUCs remain steady month-to-month The number of drilled but not completed (DUC) wells remained at 945 in January showing no change from December. However, the number of completed wells actually climbed by one to 82 in January. But that number is expected to drop as operators cease completions. 8

ND WELL COMPLETIONS VS. DUC INVENTORY (number of completions) 300 225 150 75 Completions (left axis) DUC inventory 0 Jan-13 Jul-13 Jan-14 Jul-14 Source: North Dakota Industrial Commission Jan-15 (number of DUCs) 1200 Jul-15 0 Jan-16 Just last week, Whiting Petroleum, the largest operator in North Dakota, announced it planned to cut its rig count from 11 to four, and not complete any wells until oil prices recover to at least the $40 to $45/b range. As of Friday, North Dakota sweet crude was $26.25/b. While not yet up to a sustainable level for operators, it was a substantial jump from the rock-bottom $18.07/b recorded in February. Continental Resources, another major operator in the Bakken, also said recently, that although it plans to keep four rigs active in the play, it will hold off on completions. The number of DUCs has grown over the past year in the Bakken as oil prices have plummeted and as state policy has changed to reflect market reality. Originally, North Dakota operators were only allowed to keep a well in DUC for a year before completion. However, state regulators modified the law late last year, allowing producers to apply for extensions on DUCs until commodities rebound. Drilling permits continue to fall And for the third straight month the amount of drilling permit applications filed by producers fell. Drilling permit activity declined December to January, then fell further in February as operators continue to position themselves for low 2016 price scenarios, Helms said. Operators have a significant permit inventory should a return to the drilling price point occur in the next 12 months. As of February, internal rate of return in the Bakken was 5.9%, according to Platts Bentek, an analytical unit of Platts. Brandon Evans CFTC pulls report questioning position limits rule A contested advisory panel report finding scant evidence that a federal position limits regulation was needed has been withdrawn after coming under fire from Public Citizen and two US senators. US Commodity Futures Trading Commission member J. Christopher Giancarlo said Friday that he had notified the CFTC Energy and Environmental Markets Advisory Committee that the report and recommendations had been withdrawn. The report was never intended to be a distraction from the substantive policy work of the committee and the volunteer members who give their time and expertise, he said in a statement released by the commission. Giancarlo, as the panel s sponsor, has organized much of the panel s activities. 900 600 300 The announcement comes after Tyson Slocum of Public Citizen, one of the panel s nine members, had challenged the report s validity and asserted the panel s makeup was skewed in favor of energy and trading interests rather than consumers. Senator Elizabeth Warren, Democrat-Massachusetts, then called on Giancarlo to withdraw the advisory report, and Senator Sherrod Brown, Democrat-Ohio, ranking member on the Senate Banking Committee, said the CFTC leadership needs to take a hard look at how its advisory committees are formed to ensure that the public and consumers have an adequate voice. Slocum in a statement Friday said, I applaud Commissioner Giancarlo for recognizing the report s fatal flaws, as described in my dissent, and withdrawing the report. In a dissent and at the panel s February 25 public meeting, Slocum also argued the report was not a product of deliberation by the panel and that he had not had adequate opportunity to take part in crafting the language or conclusions, aside from participating in the 8-to-1 vote on the report. In an interview Friday, Slocum said the withdrawal of the report is significant because it would have fed into legal challenges to a future position limits regulation issued by the CFTC. Wall Street trade groups and other critics of the position limits rule, I think, were hoping to use the report as a primary exhibit in a lawsuit challenging the position limits rule. That s what it is about, trying to use official apparatus of advisory committee as tool to attack the position limits rule. Giancarlo eyes advisory panel improvements Giancarlo, in his statement, said he looked forward to working with his fellow commissioners to review and improve the workings of all CFTC advisory committees, including the EEMAC. The report released February 25 had urged the CFTC to refrain from issuing a rule on speculative position limits as it is currently proposed, questioning the need for the proposal and warning it could damage already fragile liquidity in energy and environmental markets. If the commission did elect to move ahead, the report had urged the commission to make substantial changes, such as fixing the broad and unprecedented restriction on bona fide hedging it criticized in the proposal. CFTC Chairman Timothy Massad at the advisory panel s meeting had pushed back against the notion that the commission would elect not to proceed with a position limits rule, reasserting his view that Congress asked the CFTC to come up with a rule and asking the panel to work with the commission to come up with a rule that works. Maya Weber Anadarko plans to cut 1,000 jobs Anadarko Petroleum, a Texas-based oil and gas producer, will cut 1,000 jobs or about 17% of its workforce, the company said Thursday. This follows an announcement recently by Encana, a Canadian oil and gas producer, to reduce 20% of its workforce. The company will lay off about 540 people, said Doug Hock, the company spokesman. The industry is resizing, they ve built their infrastructure for unfettered growth, and now that growth is limited by global dynamics (continued on page 11) 9

Northeast April financial basis swaps move lower, but NYMEX April contract gains 3.4 cents April financial basis swaps were lower in the Northeast as the NYMEX made gains, while prices in other regions saw limited changes. The NYMEX April natural gas futures contract settled 3.4 cents higher Friday at $1.822/MMBtu. Algonquin Gas Transmission city-gates April basis stumbled 4 cents to plus 56 cents/mmbtu, while Transcontinental Gas Pipe Line Zone 6 New York came down 2.5 cents to minus 46 cents/mmbtu. Market assessments are considered preliminary and based on market activity on the IntercontinentalExchange at 2:25 pm EST (1925 GMT). Transco s proposed 1.7 Bcf/d Atlantic Sunrise expansion is facing delays as the US Federal Energy Regulatory Commission issued a schedule for the project s environmental impact statement that shows final comments due by January 2017. The project had sought FERC approval by April 2016 to meet a July 2017 in-service date. Transco has revised the target in-service date to the second half of 2017, but Platts unit Bentek Energy said the project s roughly 14-month construction schedule suggests a 2018 in-service date is more likely. The delay keeps downward pressure on Appalachian prices. Dominion South summer 2017 basis fell 1.5 cents to minus 86 cents/mmbtu. In other pipeline developments, FERC approval of REX s request to begin building its Zone 3 capacity enhancement project sets up an in-service date of winter 2016-2017 as heating demand in the Midwest will be picking up. REX said it aims to have the 800 MMcf/d of additional capacity up and running by fourth quarter of this year. The project will increase capacity by 520 MMcf/d for Lebanon deliveries, while the remaining 280 MMcf/d will be capable of traveling as far west as the REX-NGPL interconnect in Moultrie County, Illinois. The 280 MMcf/d of natural gas that reaches the Moultrie interconnect has the potential to take Midwest demand market share from west-to-east flows on REX, Bentek said. Northwest Pipeline-Rockies winter basis was down 0.25 cent to minus 0.5 cent/mmbtu. Chicago city-gates winter basis was steady at around plus 12.5 cents/mmbtu. Closer in, Chicago April basis was also steady at plus 6 cents/mmbtu. Dawn Hub in Ontario saw April basis slip 2 cents to plus 16 cents/mmbtu. Upstream in Western Canada, AECO-Alberta April basis dropped 1.75 cents to minus 78.75 cents/mmbtu. AECO summer fell 1 cent to minus 87 cents/mmbtu. To the south, Pacific Gas & Electric city-gate April basis was steady at around plus 14.5 cents/mmbtu. Southern California Gas April was down about a half-cent to minus 14.25 cents/mmbtu. Along the Gulf Coast, Houston Ship Channel April basis inched up a half-cent to minus 3 cents/mmbtu. Gulf Coast prices could get some upward pressure as Sabine Pass feedgas volumes have continued to rise, jumping 208 MMcf/d Friday to 672 MMcf/d. That marks the highest feed gas volumes seen in 2016, Bentek said. Patrick Badgley Platts M2MS Forward Curve Natural Gas, Mar 11 ($/MMBtu) Prompt month: Apr 16 Algonquin, city-gates 0.565 Transco, zone 6-NY -0.463 Texas Eastern, M-3-0.655 Columbia Gas, Appalachia -0.100 Dominion, South Point -0.740 Transco, zone 3-0.011 Transco, zone 4 0.023 Southern Natural, LA -0.028 Tennessee, 500 Leg -0.070 Florida Gas, zone 3 0.025 Columbia Gulf, mainline -0.065 Houston Ship Channel -0.030 NGPL, Texok -0.075 Chicago city-gates 0.060 MichCon city-gate 0.100 Dawn, Ontario 0.160 Panhandle, TX-Okla. -0.223 Northern, Ventura -0.065 Northern, demarc -0.065 Waha -0.170 El Paso, Permian Basin -0.220 El Paso, San Juan Basin -0.228 PG&E city-gate 0.145 PG&E, Malin -0.173 SoCal Gas -0.143 Northwest, Rockies -0.255 Northwest, Sumas -0.505 AECO, Alberta -0.788 Summer season is April-October. Winter is November-March. *Balance-of-season. El Paso, San Juan Basin: Key packages, last 30 days ($/MMBtu) 3.0 2.6 2.2 1.8 1.4 April 16 Winter 16-17 1.0 28-Jan 05-Feb El Paso, San Juan Basin: Basis market vs NYMEX ($/MMBtu) 2.4 2.2 2.0 1.8 1.6 1.4 28-Jan 05-Feb Summer 16 Cal 17 16-Feb 16-Feb 24-Feb Prompt month NYMEX Prompt month basis 24-Feb 03-Mar 03-Mar 11-Mar 11-Mar El Paso, San Juan Basin: Forward curve 3.5 ($/MMBtu) Spot price, last 30 days 3.0 2.5 2.0 1.5 1.0 0.5 0.0 April 16 May 16 June 16 July 16 August 16 Septembe 16 Summer 16 Winter 16-17 Summer 17 Winter 17-18 Summer 18 Winter 18-19 Cal 17 Cal 18 Cal 19 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 find 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. 10

Anadarko... from page 9 and competing sources of oil, said Subash Chandra, Guggenheim Partners energy analyst. Since growth is now limited, the companies have to adjust their infrastructure, Chandra said. This is the first significant adjustment they have to make in a very long time, and I hope it s the end of it, but I am not sure if this is the end of it. As exploration-and-production companies look for ways to cut costs, invest less, and reduce debt to maintain operation during this energy downturn, there may be more job cuts to come. Job cuts are companies last option Job cuts are the last action an E&P company would do to cut costs, said Chandra. The first action will be cancelling the agreements with vendors, then selling assets and cutting capital spending, and once the company has exhausted all possible actions, then it will reduce the number of workers. Last month, Anadarko said it will sell up to $3 billion of assets this year. Virtually all of the non-core asset sales are gas-related, CEO Al Walker said in a conference call. Press reports this week said Encana is exploring up to $1 billion non-core asset sales in the US and Canada. Encana s spokesman said to Platts the company does not comment on market speculation. Anadarko affirmed that it will cut 2016 capex by 50% compared with last year s spending. It will spend between $2.6 billion and $2.8 billion capital this year globally, with the largest share, about $1.1 billion, to be spent in the US onshore operation. About $1.4 billion of Anadarko capital in 2016 will be spent on international and Gulf of Mexico operations. The smallest portion, about $0.2 billion, will be invested in midstream. NYMEX Henry Hub gas futures contract, Mar 11 settlement High Low +/- Volume Apr 2016 1.822 1.859 1.792 0.034 183310 May 2016 1.915 1.947 1.887 0.032 110716 Jun 2016 2.023 2.053 1.996 0.034 37371 Jul 2016 2.121 2.151 2.093 0.035 32841 Aug 2016 2.171 2.202 2.145 0.035 20288 Sep 2016 2.190 2.220 2.161 0.036 16048 Oct 2016 2.231 2.259 2.201 0.034 21471 Nov 2016 2.407 2.427 2.374 0.032 4026 Dec 2016 2.669 2.692 2.640 0.026 3427 Jan 2017 2.800 2.830 2.787 0.024 11606 Feb 2017 2.793 2.819 2.781 0.023 2162 Mar 2017 2.759 2.790 2.737 0.021 4708 Apr 2017 2.587 2.615 2.574 0.011 3443 May 2017 2.599 2.610 2.592 0.007 587 Jun 2017 2.645 2.655 2.640 0.005 118 Jul 2017 2.689 2.700 2.688 0.004 70 Aug 2017 2.697 2.710 2.695 0.003 16 Sep 2017 2.686 2.700 2.685 0.003 3 Oct 2017 2.701 2.720 2.698 0.003 260 Nov 2017 2.775 2.790 2.775 0.003 264 Dec 2017 2.910 2.921 2.910 0.003 294 Jan 2018 3.005 3.027 3.005 0.004 37 Feb 2018 2.989 3.009 2.989 0.006 39 Mar 2018 2.929 2.949 2.929 0.006 39 Apr 2018 2.647 2.670 2.647 0.004 47 May 2018 2.643 2.660 2.643 0.005 6 Jun 2018 2.675 2.690 2.670 0.006 17 Jul 2018 2.709 2.730 2.709 0.006 1 Aug 2018 2.718 2.750 2.718 0.007 0 Sep 2018 2.708 2.730 2.708 0.007 0 Oct 2018 2.728 2.740 2.728 0.007 0 Nov 2018 2.803 2.820 2.803 0.007 0 Dec 2018 2.937 2.950 2.937 0.009 1 Jan 2019 3.032 3.062 3.032 0.009 0 Feb 2019 3.016 2.730 2.708 0.011 0 Mar 2019 2.954 2.961 2.954 0.013 1 Contract data for Thursday Volume of contracts traded: 453,181 Front-months open interest: Apr, 207,638; May, 265,274; Jun, 75.652 Total open interest: 1,092,786 Data is provided by a third-party vendor and is accurate as of 5:30 pm Eastern time. Shale Value Chain assessments, Mar 11 $/MMBtu +/- Gulf Coast ethane fractionation spread 0.963-0.181 Gulf Coast E/P mix fractionation spread 0.982-0.181 E/P mix Midcontinent to Rockies fractionation spread 0.542-0.269 HENRY HUB/NYMEX SPREAD ($/MMBtu) 1.9 Henry Hub cash price NYMEX front month close 1.8 E/P mix Midcontinent fractionation spread 0.462-0.284 National raw NGL basket price 4.679 0.016 National composite fractionation spread 2.954-0.109 The methodology for these assessments is available at: www.platts.com/im.platts.content/methodologyreferences/methodologyspecs/shale-value-chain.pdf 1.7 1.6 1.5 07-Mar 08-Mar 09-Mar 10-Mar 11-Mar Natural gas hub flow, Mar 11 Hub Name scheduled +/- % Daily 31 Day Average Flow Change Price Flow Price ANR, La. 98-36 -26.94 1.635 190 1.716 Florida city-gates 1,366-221 -13.93-1,342 1.946 Iroquois, receipts 179 10 5.91 1.620 782 2.461 Kern River, Opal plant 504 46 10.13 1.470 552 1.552 Northern, Ventura 1,209-52 -4.12 1.680 1,350 1.756 Northern, demarc 581-337 -36.71 1.680 1,319 1.755 Northwest, Can. bdr. (Sumas) 1,197 145 13.80 1.335 1,186 1.441 PG&E, Malin 1,152 71 6.59 1.540 1,059 1.601 Stanfield, Ore. 0 0-1.380 0 1.507 Transco, zone 3 955-21 -2.15 1.665 1,291 1.745 Transco, zone 6 N.Y. 1,181 131 12.51 1.055 1,601 2.725 Volumes in 000 MMBtu; prices in $/MMBtu. For more information, contact Bill Murphy at 720-264-6699. Source: Platts data Platts oil prices, Mar 11 ($/b) ($/MMBtu) Gulf Coast spot 1% Resid (1) 27.14-27.16 4.34 3% Resid (1) 24.39-24.41 3.90 Crude spot WTI (Apr) (2) 38.47-38.49 6.63 New York spot No.2 (1) 44.42-44.46 7.11 0.3% Resid LP (3) 32.16-32.18 5.15 0.3% Resid HP (3) 31.91-31.93 5.11 0.7% Resid (3) 26.91-26.93 4.31 1% Resid (3) 25.66-25.68 4.11 1= barge delivery; 2= pipeline delivery; 3= cargo delivery 11

Encana, on the other hand, will cut capital spending by 55% compared with last year, to between $900 million and $1 billion, the company said in its fourth quarter earnings report. Most of the capital will be invested in the Permian and Eagle Ford plays in the US and in the Duvernay and Montney plays in Canada. Despite experiencing a rough year, Anadarko is seen as having the potential for leverage improvements in 2017, said Brian Singer, Goldman Sachs energy analyst in a report Friday. Expected higher commodity prices in 2017 (which benefits all E&Ps), year-over-year oil production growth next year, and potential asset sales are driving the positive outlook. Fewer rigs show infrastructure adjustments Anadarko plans to reduce the number of rigs in the US onshore to five from 25, Walker said during the analyst call in February. These five rigs include one rig in the Wattenberg field in Colorado and four rigs in the Delaware Basin in West Texas and Mexico. The rig count collapse over the last year probably overshot on the downside, but as it recovers, what is the right number? Chandra asked. About 19 E&Ps provided rig-count guidance in February, which implied a reduction of 51 rigs combined, according to Marc Bianchi, Cowen and Company energy analyst. In total, about 100 to 125 additional rigs are expected to be cut in the US onshore, said Bianchi, resulting in a bottom between 375 to 400 rigs. There are 480 rigs in operation in the US, based on Baker Hughes report on March 11, nine rigs lower than the prior week and 645 rigs lower than the same week last year. Canada cut 31 rigs from the prior week and 142 from the same week in 2015. Syarifa Galeb GAS DAILY Volume 33 / Issue 49 / ISSN: 0885-5935 Gas Daily Questions? Email: NAGas&Power@platts.com Manager North America Gas and Power Content Rocco Canonica, +1-720-264-6626 Matthew Eversman, +1-713-655-2238 Beth McKay, +1-713-655-2258 Anne Swedberg, +1-720-264-6728 Editors Brandon Evans, +1-720-264-6671 Syarifa Galeb, +1-713-655-2282 Jim Magill, +1-713-658-3229 Jasmin Melvin, +1-202-383-2135 Chris Newkumet, +1-202-383-2141 Mark Watson, +1-713-658-3214 Spot Market Editors Patrick Badgley, +1-713-658-3267 Art Fresquez, +1-713-655-2279 Ashish Kothari, +1-713-655-2241 Curt Mrowiec, +1-713-658-3271 Charles Noh, +1-713-658-3259 Advertising Tel : +1-720-264-6631 Analysts Eric Brooks Richard Frey John Hilfiker Tyler Jubert George McGuirk Mason McLean Jonathan Nelson Thad Walker Ross Wyeno Director, Global Gas and Power Pricing Mark Callahan Director, Global Gas and Power Content James O Connell Global Editorial Director, Gas and Power Simon Thorne Chief Content Officer Martin Fraenkel Platts President Imogen Dillon Hatcher Manager, Advertisement Sales Kacey Comstock To reach Platts: E-mail:support@platts.com; North America: Tel:800-PLATTS-8; Latin America: Tel:+54-11- 4121-4810; Europe & Middle East: Tel:+44-20-7176-6111; Asia Pacific: Tel:+65-6530-6430 Gas Daily is published daily by Platts, a division of McGraw Hill Financial, registered office: Two Penn Plaza, 25th Floor, New York, N.Y. 10121-2298. 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Weekly Gas Market Data Basis differential for week ended Mar 11 Henry El Paso Agua Transco Katy Kern, Panhandle Chicago Col. Gas SoCal Hub Permian Dulce Zone 3 opal Tx.-Ok. city-gates Appa. Gas Weekly WACOG 1.54 1.38 1.57 1.52 1.53 1.36 1.38 1.66 1.43 1.44 Henry Hub 0.16-0.03 0.02 0.01 0.18 0.16-0.12 0.11 0.10 El Paso, Permian -0.16-0.19-0.14-0.15 0.02 0.00-0.28-0.05-0.06 Agua Dulce 0.03 0.19 0.05 0.04 0.21 0.19-0.09 0.14 0.13 Transco Zone 3-0.02 0.14-0.05-0.01 0.16 0.14-0.14 0.09 0.08 Katy -0.01 0.15-0.04 0.01 0.17 0.15-0.13 0.10 0.09 Kern, Opal -0.18-0.02-0.21-0.16-0.17-0.02-0.30-0.07-0.08 Panhandle, Tx.-Ok. -0.16 0.00-0.19-0.14-0.15 0.02-0.28-0.05-0.06 Chicago city-gates 0.12 0.28 0.09 0.14 0.13 0.30 0.28 0.23 0.22 Col. Gas Appa. -0.11 0.05-0.14-0.09-0.10 0.07 0.05-0.23-0.01 SoCal Gas -0.10 0.06-0.13-0.08-0.09 0.08 0.06-0.22 0.01 NYMEX Basis -0.282-0.442-0.252-0.302-0.292-0.462-0.442-0.162-0.392-0.382 NYMEX Basis is the NYMEX Henry Hub/cash basis differential calculated from the near-month settlement of $1.822. Henry Hub futures and strips 03/07 03/08 03/09 03/10 03/11 mon Tue Wed Thu Fri Apr-016 1.690 1.712 1.752 1.788 1.822 May-016 1.789 1.803 1.846 1.883 1.915 Jun-016 1.892 1.906 1.946 1.989 2.023 Jul-016 1.986 2.001 2.041 2.086 2.121 Aug-016 2.035 2.051 2.091 2.136 2.171 Sep-016 2.050 2.066 2.106 2.154 2.190 Oct-016 2.094 2.105 2.147 2.197 2.231 Nov-016 2.273 2.271 2.311 2.375 2.407 Dec-016 2.549 2.539 2.572 2.643 2.669 Jan-017 2.677 2.670 2.703 2.776 2.800 Feb-017 2.676 2.669 2.700 2.770 2.793 Mar-017 2.646 2.641 2.670 2.738 2.759 3/strip 1.790 1.807 1.848 1.887 1.920 6/strip 1.907 1.923 1.964 2.006 2.040 9/strip 2.040 2.050 2.090 2.139 2.172 12/strip 2.196 2.203 2.240 2.295 2.325 ($/MMBtu) 2.4 2.2 Bentek Canadian gas storage data for week ended Mar 11 (in Bcf) east West Total Working gas 130.38 422.39 552.77 Weekly Change 2.22 3.74 5.96 % of capacity 49.57% 75.03% 66.92% Working Gas Mar 13, 2015 45.81 274.19 320.00 CANADIAN STORAGE INVENTORIES (Bcf) 800 700 600 500 400 2015 300 2016 3-Year Avg 200 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Source: Platts Bentek 2.0 1.8 3-month 12-month Prompt month 1.6 12-Feb 18-Feb 24-Feb 01-Mar 07-Mar 11-Mar CFTC Commitment of Traders Report for week ended March 08 long short net position net position change in % market % market positions positions last week overall positions share share last week Producers/merchants/processors/users 134,147 131,301 50.54% long 50.15% long 8.24% 21.64% 20.99% Swap dealers 202,981 27,182 88.19% long 88.84% long 7.7% 18.76% 18.29% Money managers 192,554 370,539 65.8% short 65.55% short 2.53% 45.9% 47.01% Other reportables 69,424 98,786 58.73% short 56.48% short 5.05% 13.71% 13.71% 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 13

REGISTER EARLY and SAVE $300 11th Annual NORTHEAST POWER AND GAS MARKETS CONFERENCE Pre-Conference Workshop May 23, 2016 Main Conference May 24 25, 2016 New York Hilton Midtown New York, NY Join us at our 11th Annual Northeast Power and Gas Markets Conference. This long-standing event attracts a variety of power generators, regulators, renewable, transmission, and pipeline companies to exchange best practices and gain cutting-edge knowledge of trends and challenges transforming the Northeast power market. DON T MISS OUR PRE-CONFERENCE WORKSHOP MONDAY, MAY 23, 2016: How Much is Too Much? Debating New England s True Pipeline Requirements and Whether LNG is a Viable Solution Platts analysts will host a half day workshop that will focus on gas flow into the Northeast. Is building more pipelines the answer? Could LNG be the more economical route? Join Platts and other leading industry experts as they debate this critical issue impacting the Northeast. Further details can be found at: www.platts.com/northeast For speaking opportunities, contact: Erica Giardina Tel: 857-383-5718 erica.giardina@platts.com For sponsorship and exhibit opportunities, contact: Lorne Grout Tel: 857-383-5702 lorne.grout@platts.com For media partnership, contact: Khushi Bhatia Tel: 857-383-5725 khushi.bhatia@platts.com BOOK NOW www.platts.com/northeast registration@platts.com 800-752-8878 (toll free) +1 212-904-3070 (outside USA & Canada)