1

IN THIS ISSUE

Forecast assumptions and rationale for current trigger objective levels.

Suggestions based on fundamental and technical data.

In-depth discussion of market factors that impact decision making.

Commentary on market drivers.

Charts of forward market price strips.

Suggestions to help you when making pricing decisions.

Market analysis and regulatory updates specific to electricity.

JUNE 2016

eforecasterA Guide to Natural Gas Triggering and Electricity Markets

JUNE 2016eforecaster

2

Direct Energy Business is more than just a retail energy supplier. We have a distinct focus on helping to make your business better. We provide straightforward guidance and an exceptional customer experience to help you make the most of the energy opportunities available to you.

Helping to make your business better means delivering more than an operational line item. It means sharing our knowledge and making smart energy choices easy and clear. Direct Energy Business can help your business leverage the right mix of energy supply and services to address your energy concerns.

Direct Energy Business offers its customers a portfolio-based approach to managing the Henry Hub commodity portion of their natural gas price risk and energy portion of their electricity price risk. This monthly report lays out three risk-adjusted price levels that we believe have a realistic chance of being reached in the current market environment. When establishing these objective levels, Direct Energy Business considers both current and forecasted market fundamentals, as well as quantitative technical price analyses.

Our below-market trigger levels are consistent with areas of major price support based on our technical analysis of the natural gas futures market. The natural gas program also recommends stop loss levels that correspond with points of major technical price resistance that, if traded through, could target much higher highs. Electricity trigger recommendations, on the other hand, are based on natural gas prices and “heat rate” assumptions for each time period in the regions listed in the Electricity trigger table.

Customers assume a certain level of risk by participating in Dynamic Triggering and Direct Energy Business makes no guarantee that any level of triggers will be reached. Participation in Dynamic Triggering leaves customers open to potentially significant upside price risk if trigger levels are not reached in a rallying market. Therefore, Direct Energy Business suggests natural gas customers consider the use of above market stop loss orders in conjunction with below market triggers to protect themselves from substantial rallies in natural gas wholesale prices.

2

The natural gas and electric trigger levels outlined in this report are recommendations only. Customers should use their own discretion when setting forward triggers and base them on their company’s budgetary goals and risk tolerance.

Did You Know?You can set trigger alerts atbusiness.directenergy.com If you would like to be notified when the market reaches a certain price, just set a trigger alert through your online account and you will receive an e-mail. It’s that simple!

Visit the Online Customer Care center at business.directenergy.com.

JUNE 2016eforecaster

3

Conservative (Relatively Low Risk)

Conservative objectives are for risk adverse customers, who desire to reduce short term price exposures. These objectives have a relatively high probability of being reached in the short term. Conservative objectives are usually based upon the first significant level of below market technical support but may take the form of a buy at market recommendation in a bull market.

Moderate (Medium Risk)

Moderate objectives are for customers who are comfortable taking moderate levels of risk in order to achieve more attractive price levels in the intermediate term. Moderate objectives are usually based on a key technical support pivot or trend line support but may take the form of a buy at market recommendation in a bull market.

Aggressive (Potentially High Risk)

Aggressive objectives assume a high degree of risk as they attempt to identify market bottoms or seasonal cycle lows. These objectives are for customers with a high tolerance for risk and who can accept the high price volatility of Henry Hub commodity exposure. Aggressive objectives are longer term and are usually based on major technical support levels that are often associated with one of the more bearish case outlooks.

TRIGGER OBJECTIVES

Explanation of Trigger Objective Tiers and Associated Risk

Current Recommendations for Dynamic Trigger Objectives

NYMEX Settle6/6/2016

Conservative (Low Risk)

Moderate (Medium Risk)

Aggressive(High Risk)

July ‘16 $2.47 $2.350 - $2.250 $2.250 - $2.150 $2.100 - $2.000

Aug ‘16 $2.54 $2.350 - $2.250 $2.250 - $2.150 $2.100 - $2.000

Sept ‘16 $2.57 $2.350 - $2.250 $2.250 - $2.150 $2.100 - $2.000

Oct ‘16 $2.65 $2.350 - $2.250 $2.250 - $2.150 $2.100 - $2.000

July ‘16 - Oct ‘16 $2.56 $2.350 - $2.250 $2.250 - $2.150 $2.100 - $2.000

Nov ‘16 - Mar ‘17 $3.06 $2.850 - $2.750 $2.550 - $2.450 $2.450 - $2.350

Jan ‘17 - Dec ‘17 $3.02 $2.850 - $2.750 $2.550 - $2.450 $2.450 - $2.350

Jan ‘18 - Dec ‘18 $3.04 $2.850 - $2.750 $2.550 - $2.450 $2.450 - $2.350

JUNE 2016eforecaster

4

TRIGGER OBJECTIVES

Rationale for Current Trigger Objective LevelsTrigger levels through March 2017 were increased 25 to 10 cents due to summer demand risks. Weather forecasts for the Jul-Aug 2016 time period continue to reflect that a majority of key consuming regions will experience above normal temperatures. This implies that storage injections could be substantially lower than in 2015 and the bullish psychology could spill over into winter 2016-17. Additionally, and not a surprise to the author, power sector demand has again set records in 2016 and this is supporting prices even in lower demand periods due to a combination of low gas prices and increasing power plant efficiencies.

Calendars 2017 & 2018 levels were increased 10 cents due to the potential knock-on effect of strong nearby prices on longer dated terms.

EXECUTIVE SUMMARY

Recap/Price Outlook/Key ThemesMay, which is typically a lower demand month, was just the opposite in 2016. As per Bentek Energy LLC during May 2016 (MTD Y-o-Y) gas demand (including Mexico/LNG exports) was a ~4.2 bcf/day surplus (Please see sector data below). The biggest increase came from the Residential/Commercial sector due to the coldest temperatures in the last 5 years. The Power sector was the second highest demand (0.8 bcf/d MTD Y-o-Y). A combination of low gas prices and increased power plant efficiencies led to record generation demand for May in the Midwest as per Bentek Energy LLC.

Adding to the increasingly tightening supply/demand balance overall supplies were down 1.1 bcf/d , driven by lower domestic production. Summer prices were marginally lower M-o-M in early May but they rebounded to prior report levels by June 1st due to market expectations of higher power sector demand moving into the season. Record setting exports to Mexico and LNG exports from Sabine Pass are lending bullish support to the demand picture.

Gas production outside of the northeast region declined by approximately 4 bcf per day in May due to break even costs higher than current price levels and lower gas output associated with lower crude oil output again due to the same factors as gas. The northeast (~2.8 bcf/day higher in May MTD Y-o-Y) region continued to buck the declining production trend due to low extractions costs and extremely financially astute producers, i.e. they have utilized hedging to an extremely high degree to lock in margins in 2016.

The price outlook is unchanged M-o-M; stable to increasing for the 2016 summer period and beyond. Y-o-Y demand increases from the power/industrial sectors and increasing Mexico/LNG exports are widely expected, plus throw in the potential of a hot summer and rising prices in 2016 and into 2017 are a high probability. The author’s opinion is that a supply/demand balance shift of 4 bcf/day or greater could lead to summer prices sustaining above the $2.50 level. The reasoning is a net gain of over 4 bcf per day would negate almost all of the surplus gas available (~4.6 bcf/d) due to the huge end of May storage surplus.

Short Term Price Impacts

• Northeast dry gas production is ~2,800,000 dth/day HIGHER MAY16 MTD Y-o-Y BUT U.S. production is ~1,500,000 dth/day lower

• Total U.S. Demand (including LNG gas and Mexico exports) ~4,200,000 dth/day HIGHER MAY16 MTD Y-o-Y (Note: MAR 2016 was ~5.7 bcf/day LOWER MTD)

• U.S. Y-o-Y storage surplus as of May 27th at 712 bcf = 4.5 bcf/day LESS injection demand to match OCT 2015

• U.S. Industrial demand continues to trail EIA forecasts as per Bentek Energy LLC real time data

• U.S. LNG/Mexico exports and Power sector demand ~0.5/~0.7 and ~0.8 bcf/day higher MAY16 MTD Y-o-Y

Medium/Long Term Price Impacts (2017-2020)

• U.S. gas/oil producer extraction costs per unit produced lowest in history implying further declines limited

• Low global oil prices may limit LNG/LPG export growth; wet gas production may decline if sub-$50/bbl persists

• Low global oil prices make global chemical/fertilizer plant

feed stocks more competitive with the U.S.; this may limit NG demand from those two sectors

• U.S. renewable energy growth may limit gas fired power generation demand (Please click here to view ISO-NE presentation that discusses Renewables growth)

• U.S. LNG/Mexico exports to increase

JUNE 2016eforecaster

5

EXECUTIVE SUMMARY (CONTINUED)

Total U.S. demand (including exports) was ~4.2 bcf/day higher May MTD Y-o-Y and ~5.6 for the first two days in June led by an ~7 bcf/day increase in power sector demand. This massive demand increase due to above normal temperatures during the two day period may have been a foreshadowing for the market of potential demand surges that might occur from the sector if a hot summer were to materialize. The Natural Gas Supply Association forecast a 4.1 bcf/day summer 2016 demand increase with 3.1 of that coming from power generation (Please click here to read article). The EIA forecast a more modest 1.7 bcf/d Y-o-Y power sector summer increase (Jun-Jul-Aug; May 2016 STEO).

As an example, the PJM electric region alone will see a 0.75 to 1 bcf/d increase in gas fired generation demand starting June 1st which is the start of a new capacity year.

The bottom line is summer and potentially forward gas prices will continue to be supported or driven higher by the power generation sector, especially if near normal summer weather occurs.

For the balance of 2016 and 2017, LNG exports from Sabine Pass will remain a price supporting factor for the Henry Hub region as will exports to Mexico which are forecast to set a new record in 2016 to ~4 bcf/d or ~400,000 dth/d increase from June 2016 levels.

U.S. Gas Demand:

Price Outlook SummaryThe author’s opinion is that the NYMEX 12 month strip and calendars 2017 through 2021 will remain between $2.50 and $3.50 in June. If summer temperature patterns turn abnormally hot the July-August 2016 contracts could surge above the $2.50 level and the Nov16-Mar17 winter strip ($3.05 as of early June) could reach the most recent price high at $3.50 level (or higher). Calendar prices 2018-2020 have risen to a lesser degree than the balance of 2016 and 2017. It appears that the market has chosen to react to a greater degree to near term data while taking a wait and see approach longer term due to producers ability to quickly ramp up production if longer dated prices were to move over the $3.50 mark.

U.S. Gas Production: Gas production outside of the northeastern U.S. is over 4 bcf/day lower due to regional spot/forward prices below levels that support sustainable ROI’s. Lower crude oil production (~840K BPD or ~9% lower from June 2015 peak) has also led to significant declines in associated gas production and again the culprit is sub-$50/bbl prices that cuts ROI’s. The Northeast (NE) continues to maintain a Y-o-Y surplus of nearly 3 bcf/day. As mentioned above NE extraction costs are the lowest in the nation and producers in the region significantly hedge future production, i.e. lock in ROI’s.

Northeast gas production can have a significant impact on Henry Hub prices during both high and low demand periods. When demand spikes in the north less gas is required to move south to north. In lower demand periods gas can move out of the region, especially with significant export capacity now available into both the midcontinent and recently the US Gulf Coast. This link (i.e., increasing “backhaul” capacity) implies that significant changes in northeast production could have significant implications on prices in the Henry Hub and midcontinent regions.

So, what may happen to northeast production in the future?

Rig counts in the region are near the lowest ever recorded and a significant portion of the rigs may be retired if producers were to give an indication that they do not intend to ramp up production in the next 1-2 years due to uneconomic forward prices and declining hedge positions.

Additionally, the well backlog in the region (i.e. future production) is being reduced in lieu of declining rigs which implies a potential for less future gas production especially if rig counts remain low.

The bottom line is that 2016 may be a last year of a substantial Y-o-Y production surplus in the northeastern U.S. for the next 2-3 years unless there is an upward change in the forward price curve and/or improved prospects for export capacity out of the region. (There has been significant push back from varied entities opposed to “greenfield” natural gas pipeline projects. This could slow or cancel development of future projects.)

JUNE 2016eforecaster

6

(Source: Bentek Energy LLC)

Dth/day MTD YTD

Supply* -700,000 -200,000

Demand* +5,400,000 -2,100,000

U.S. Table (ao 6/03/2016; Gain/Loss versus 2015)

*Supply = U.S. Dry + Imports + NGL/Other Declines; *Demand = U.S. + Mexico Exports

Dth/day MTD YTD

Supply* +2,627,000 +3,154,000

PA Marcellus +1,685,000 +1,464,000

Demand* +1,214,000 -1,827,000

Northeast U.S./Marcellus Production/Demand Table (ao 6/01-03/2016; Gain/Loss versus 2015)

NOTES:1,000,000 dth = 1 Billion cubic feet (Bcf) | MTD - Month to Date | YTD - Year to Date | Y-o-Y = Year over Year | MTD Y-o-Y = 2016 MTD vs. 2015 MTD | YTD Y-o-Y = 2016 YTD vs. 2015 YTD

Want to reduce costs and become more energy efficient?With an increased focus on the environmental impact of doing business, renewable energy is becoming an important component of corporate energy strategies. Direct Energy Business believes energy solutions that are good for our environment can be great for your business. We offer various strategies that can help you meet your environmental commitment. Contact your Direct Energy Business sales representative to learn more.

Fundamental Overview: June 2016 MTD/YTD Y-o-Y

• Dry gas production ~1.2 bcf per day lower

• Residential/Commercial ~2.1 bcf per day lower

• Power sector demand ~6.9 bcf per day higher

• Industrial sector demand ~0.5 bcf per day lower

• Mexican exports ~0.4 bcf per day higher

• LNG feedstock ~0.6 bcf per day higher

Note; As per Bentek Energy LLC total northeastern U.S. gross production & PA Marcellus reached a record at ~23.1 Bcf & ~14.3 Bcf day/week ended 2/11/16 & 2/10/16

*Supply = Production (Grossed) + LNG +/- Inflows; *Demand = NE Demand +/- Outflows

MTD/Y-O-Y SUMMARY TABLES

JUNE 2016eforecaster

7

EXECUTIVE SUMMARY

EIA Short Term Energy Outlook Report 5/10/16 (http://www.eia.gov/emeu/steo/pub/contents.html)

Unless noted, the following text is taken directly from the monthly EIA Short Term Energy Outlook Report (link to full report listed above)

Marketed natural gas production was 80.1 billion cubic feet per day (Bcf/d) in February 2016, according to the latest Natural Gas Monthly data, which is the second-highest production level on record and an increase of 1.4% from January. Growth was strongest in the Marcellus and Utica production areas. Production in Pennsylvania (measured in Bcf/d) increased by 3.5% from January levels, and production in Ohio and West Virginia increased by 10.7% and by 1.7%, respectively. However, preliminary data since February, including EIA’s Drilling Productivity Report, indicate production growth may be slowing because of reduced drilling activity in response to low natural gas prices.

U.S. Natural Gas Consumption EIA’s forecast of U.S. total natural gas consumption averages 76.5 Bcf per day (Bcf/d) in 2016 and 77.4 Bcf/d in 2017, compared with 75.3 Bcf/d in 2015. In 2016, natural gas consumption increases in the electric power sector primarily drive increases in total consumption. Forecast electric power sector use of natural gas increases by 4.0% in 2016, then declines by 1.6% in 2017, as natural gas prices rise and contribute to increasing coal generation. Forecast industrial sector consumption of natural gas increases by 2.4% in 2016 and by 2.0% in 2017, as new fertilizer and chemical projects come online.

U.S. Natural Gas Production and Trade Despite recent data showing growing natural gas production in February, more recent preliminary data indicate production may be leveling in the next few months. EIA forecasts relatively unchanged production through the rest of 2016, as low natural gas prices and declining rig activity begin to affect production. In 2017, however, production is expected to rise in response to increases in price, demand, and liquefied natural gas (LNG) exports. Overall, EIA expects production will rise by 0.9% in 2016 and by 2.2% in 2017.

EIA expects natural gas exports by pipeline to Mexico will increase because of growing demand from Mexico’s electric power sector and flat natural gas production in Mexico. EIA projects LNG gross exports will increase to an average of 0.5 Bcf/d in 2016, with the startup of Cheniere’s Sabine Pass LNG liquefaction plant in Louisiana, which sent out its first cargo in February 2016. EIA projects gross LNG exports will average 1.3 Bcf/d in 2017, as Sabine Pass ramps up its capacity. U.S. Natural Gas InventoriesInventories in March ended at 2,478 Bcf, the highest end-ofwithdrawal-season level on record. The first significant inventory increase of the injection season occurred the week ending April 22, with a 73-Bcf build. Looking to the start of next winter, EIA forecasts inventories to be 4,158 Bcf at the end of October 2016, which would be the highest level on record to begin the heating season.

U.S. Natural Gas PricesThe Henry Hub natural gas spot price averaged $1.92/million British thermal units (MMBtu) in April, an increase of 19 cents/MMBtu from the March price. Through the 2015-16 winter, prices remained relatively low because of lower demand as a result of warmerthan-normal temperatures, record inventory levels, and production growth. EIA expects prices will gradually rise through the summer, as demand from the electric power sector increases, but forecast prices remain lower than they were last summer. Monthly average Henry Hub spotprices are forecast to remain lower than $3.00/MMBtu through December 2016. Forecast Henry Hub natural gas prices average $2.25/MMBtu in 2016 and $3.02/MMBtu in 2017.

Natural gas futures contracts for August 2016 delivery that were traded during the five-day period ending May 5 averaged $2.36/MMBtu. Current options and futures prices imply that market participants place the lower and upper bounds for the 95% confidence interval for August 2016 contracts at $1.64/MMBtu and $3.39/MMBtu, respectively. In early May 2015, the natural gas futures contract for August 2015 delivery averaged $2.85/MMBtu, and the corresponding lower and upper limits of the 95% confidence interval were $1.98/MMBtu and $4.11/MMBtu.

End EIA Short Term Energy Outlook Report Excerpt.

JUNE 2016eforecaster

8

TECHNICAL ANALYSIS

Fibonacci Price Retracement

TREND: U = UP | D = DOWN | RB = RANGE BOUND | High(H)/Low(L) = Settlements

STOP-LOSS logic is based on 2 weekly settlements above levels; budget constraints should override

NYMEX 6/6/16 3M High 3M Low Last3M

Trend

Stop

LossComments

JUL ‘16 - OCT ‘16 $2.50 $1.94 $2.50 U $2.50 Support at $2.00

NOV ‘16 - MAR ‘17 $3.05 $2.56 $3.04 U $3.15 Support at $2.55

CAL 2017 $3.02 $2.62 $3.01 D $3.05 Support at $2.65

http://www.investopedia.com/ask/answers/05/FibonacciRetracement.asp

RSI Price Indicator: http://www.investopedia.com/terms/r/rsi.asp

The NYMEX natural gas spot price has peaked on average June 8th from 2007-2015. This implies that prices may decline into the next seasonal low in August (on average) if summer temperatures are not above normal.

JUNE 2016eforecaster

9

MARKET FACTORS

Summary Table of Bullish-Neutral-Bearish Market Factors

Bullish Neutral Bearish Comments

U.S. Dry Production • ~1,200,000 dth/day lower MAY MTD Y-o-Y

(Bentek Energy LLC)

Canadian Imports Near 5 year seasonal lows; ~400,000 dth/day higher JUN MTD Y-o-Y

LNG Exports • Sabine Pass exports begin; feed gas ~600,000 dth/day higher

Power Generation • ~6,900,000 dth/day higher JUN MTD Y-o-Y

Industrial Demand • ~500,000 dth/day lower JUN MTD Y-o-Y

Managed Money Participation • Significant decrease in near record high NET

short position (CFTC)

Weather • JUL 2016 – Forecasted warmer than 2015/10Y/30Y avg. across

all regions except TEXAS

NG Storage • 2nd highest 712 bcf Y-o-Y surplus May 27th

Technical Outlook • Technical indicators – Near overbought

EPA Regulations • Mercury Air Toxics Standards (MATS) rule in effect 2015

JUNE 2016eforecaster

10

FUNDAMENTALS IN-DEPTH

U.S. StorageThe storyline related to storage remains unchanged and only slightly less bearish (i.e. price impact) due to summer weather forecasts that call for normal/above normal temperatures.

A 712 bcf Y-o-Y storage surplus on 05/27/2016 equates to ~4 bcf/day less injection demand if 2016 peak levels equaled 2015 (4,009 bcf on 11/20/2015). (4.5 to match Oct 31, 2015)

Can the market absorb the gas? So far, in April and May market balancing forces are off to a good start as about 300 bcf (or 30-40 bcf/week) has been reduced from the 1,017 bcf surplus record in March.

During the Jun-Oct time period what may occur to keep this trend intact?

• U.S. production declines of 4 bcf/day outside of the northeast

• Exports to Mexico are, and should remain, ~0.5 to ~1 bcf/day higher Y-o-Y

• LNG export demand has increased to ~600,000 dth/day; this level should be sustained and increase to ~1 bcf/day through 2016

• Power Sector demand is ~7 bcf/day higher JUN MTD Y-o-Y but record demand will need to sustain this gain through the Jun-Oct time period in order to level the storage overhang

The author’s opinion is that power sector demand during the 2016 summer will surprise to the upside as hedging (i.e. buy forward gas/sell forward power) during the record setting lows in late February and higher plant efficiencies/utilization factors that will be seen as new plants come online (i.e. PJM June 1st 2016= ~0.75 to ~1 bcf/day demand increase) combine to take sector demand to new all-time highs.

Most industry forecasts, which were predicting a maximum storage capacity event just a few months ago, are now forecasting October levels to top out just above 4.1 Tcf.The author believes that a maximum capacity scenario is still possible but it will be well known prior to that happening and operational issues, i.e. storage injection demand is limited by operational capacity, will force U.S. producers to shut-in gas thereby lowering the probability of fire sale natural gas prices. We will keep you apprised in daily and weekly reports.

Link to EIA Weekly NG Storage Report Click here to view EIA Storage Capacity report

WeatherA majority of forecasts are predicting above 30Y normal temperatures for July and August (Please see table on next page). Tropical season forecasts are mixed but there are a few that predict the possibility of an above normal Atlantic Basin tropical season (Jun 1st – Nov 30th). The EIA reported that USGOM gas production was ~3.6 bcf/day in March (early June Bentek Energy LLC data concurs). This is only 5% of U.S. production but it must be noted that Bentek Energy data reflects that Texas and southeastern U.S. gas production is ~3.7 bcf/day lower June MTD Y-o-Y. This data alone supportive of pricing at the Henry Hub; add in the potential for losses, possibly for extended periods, from tropical activity and one could conclude that price risk at the Henry Hub may be higher than in the 5 past years and possibly a cautious perspective may be warranted.

“May 27, 2016NOAA’s Climate Prediction Center says the 2016 Atlantic hurricane season, which runs from June 1 through November 30, will most likely be near-normal, but forecast uncertainty in the climate signals that influence the formation of Atlantic storms make predicting this season particularly difficult.”

NOAA Excerpt 05/27/2016; Please click here to read Press Release

Link to NOAA El Nino WebsiteLink to NOAA ENSO Website

JUNE 2016eforecaster

11

FUNDAMENTALS IN-DEPTH

Weather Links:http://www.cpc.ncep.noaa.gov/products/predictions/90day/http://www.cpc.noaa.gov/products/predictions/610day/index.phphttp://www.cpc.noaa.gov/products/predictions/814day/index.phphttp://www.cpc.noaa.gov/products/predictions/schedule.htmlhttp://www.cpc.ncep.noaa.gov/products/analysis_monitoring/cdus/degree_days

MONTH2016

Forecasters Range

2015 10Y 30Y Comments

JUL ’16GWCDD 365-390 357 358 338

Regional Consensus - Warmer Northern U.S.

AUG ’16GWCDD 345 386 331 312

Regional Consensus - Warmer Northern U.S.

PWCDD/GWHDD = Population Weighted Cooling Degree Day/Gas Weighted Heating Degree Day; Historical = EarthSat

Forecasts: May Consensus: Above normal upper tier of U.S.

Weather (continued)

U.S. Natural Gas Demand• 2016 Power sector demand forecasted to remain near 2015

record highs

• Demand near the Henry Hub expands 600,000dth/day (or greater) as U.S. LNG exports from Sabine Pass began February 2016 and a second unit online by Q3 2016

• Exports to Mexico and Canada to increase in 2016

• U.S. Industrial demand, which has trended lower Y-o-Y in 2015, may be at risk in 2016 if global oil prices remain low

JUNE 2016eforecaster

12

FUNDAMENTALS IN-DEPTH

U.S. Natural Gas Demand (continued)

U.S. Production• Northeast Y-o-Y production ~2.8 bcf/day higher

• All other regions of the U.S. ~4 bcf/day lower Y-o-Y

• 2H 2016 Y-o-Y gains may be limited due to declining oil output that impacts shale oil “associated’ gas production

• 2H 2016 Y-o-Y gains may be limited due to declines from existing wells outweighing new production

• Well backlog depletions lowers future production potential

Link to Monthly EIA Drilling/Shale Gas Report

Link to Monthly EIA Y-o-Y Drilling Summary Report

JUNE 2016eforecaster

13

FUNDAMENTALS IN-DEPTH

U.S. Regional Fixed Prices:• 2017 U.S. regional fixed prices higher due to increases in both commodity and basis prices

• Only gas export constrained regions sub-$3.00

Potential Impacts: Slower Y-o-Y production growth beyond 2016, a lack of continued pipeline expansions (i.e., less takeaway capacity) and higher power sector demand in 2016 (and beyond) could limit downside price moves in both the gas commodity and basis markets.

JUNE 2016eforecaster

14

Bearish/Neutral Statistic: Price below 2016 spot high | Bullish/Neutral Statistic: Price above 50/100 day moving averages

NYMEX NG Daily Spot Price Chart:

TECHNICAL ANALYSIS

Price Charts

NYMEX NG Daily 12 Month Continuation Strip Price Chart:

Bearish/Neutral Statistic: Price below 1Y year high | Bullish/Neutral Statistic: Price above 50/100 day moving averages and 2016 high

JUNE 2016eforecaster

15

TECHNICAL ANALYSIS

Bearish/Neutral Statistic: Price below 1Y high | Bullish/Neutral Statistic: Price above 50/100 day moving averages and 2016 high

Price charts: FutureSource

NYMEX NG Daily 24 Month Continuation Strip Price Chart:

Price Charts (continued)

Fibonacci Price Retracement http://www.investopedia.com/ask/answers/05/FibonacciRetracement.asp

STOP LOSS RECOMMENDATIONS

All or Partial Energy Consumption$2.50 is a key price resistance level for July 16-Oct16 (Unchanged M-o-M due to recent price action)

Stop loss orders are recommended, as always, if budget issues are critical. STOP-LOSS logic is based on 2 weekly settlements above levels, but budget constraints should override.

A breach of the above levels should be viewed as potential stop-loss areas; price increases above these target levels would imply a significant change in the supply/demand balance that may not be relieved in the short term.

A breach of the above levels could also be a call to action for seasonal/calendar price strips further out the price curve.

While a traditional fixed price hedge will give you 100% upside protection in a Henry Hub commodity price rally, it will offer absolutely no downside price participation if the market declines. Another solution would be to consult your Direct Energy Business Development Manager (BDM) regarding Direct Energy Business Price Protection product offering.

Your BDM, the Direct Energy Business Commodity Services, Natural Gas Desk and/or the Direct Energy Business Market Strategist are available to update you with market data that will help you when making pricing decisions.

JUNE 2016eforecaster

16

Conservative (Relatively Low Risk)

Conservative objectives are for risk-averse customers who desire to reduce short-term price exposures. These objectives have a relatively high probability of being reached in the short term. Conservative objectives are usually based upon the first significant level of below market technical support but may take the form of a buy at market recommendation in a bull market.

Moderate (Medium Risk)

Moderate objectives are for customers who are comfortable taking moderate levels of risk in order to achieve more attractive price levels in the intermediate term. Moderate objectives are usually based on a key technical support pivot or trend line support but may take the form of a buy at market recommendation in a bull market.

Aggressive (Potentially High Risk)

Aggressive objectives assume a high degree of risk as they attempt to identify market bottoms or seasonal cycle lows. These objectives are for customers who can accept the high price volatility of Henry Hub commodity exposure. Aggressive objectives are longer term and are usually based on major technical support levels often associated with one of the more bearish case outlooks.

Electricity - Current Trigger Recommendations

ATC6/6/2016

Conservative (Low Risk)

Moderate (Medium Risk)

Aggressive(High Risk)

July ‘16 $35.60 $33.90 - $32.40 $32.40 - $31.10 $30.30 - $28.80

Aug ‘16 $34.40 $31.80 - $30.50 $30.50 - $29.10 $28.40 - $27.10

Sep ‘16 $29.00 $26.50 - $25.40 $25.40 - $24.30 $23.70 - $22.60

Oct ‘16 $28.70 $25.50 - $24.40 $24.40 - $23.30 $22.70 - $21.70

July ‘16 - Oct ‘16 $31.95 $29.30 - $28.10 $28.10 - $26.80 $26.20 - $25.00

Nov ‘16 - Mar ‘17 $38.90 $36.20 - $35.00 $32.40 - $31.10 $31.10 - $29.90

Jan ‘17 - Dec ‘17 $33.90 $32.00 - $30.90 $28.60 - $27.50 $27.50 - $26.40

Jan ‘18 - Dec ‘18 $32.75 $30.90 - $29.80 $27.70 - $26.60 $26.60 - $25.50

Electricity - PJM Western Hub

JUNE 2016eforecaster

17

Electricity - NYISO Zone A

ATC 6/6/2016

Conservative (Low Risk)

Moderate (Medium Risk)

Aggressive(High Risk)

July‘16 $35.20 $33.50 - $32.10 $32.10 - $30.60 $29.90 - $28.50

Aug ‘16 $32.60 $30.20 - $28.90 $28.90 - $27.60 $27.00 - $25.70

Sep ‘16 $23.65 $21.60 - $20.70 $20.70 - $19.80 $19.30 - $18.40

Oct ‘16 $24.55 $21.80 - $20.80 $20.80 - $19.90 $19.50 - $18.50

July ‘16 - Oct ‘16 $29.00 $26.60 - $25.50 $25.50 - $24.40 $23.80 - $2.70

Nov ‘16 - Mar ‘17 $36.50 $34.00 - $32.80 $30.40 - $29.20 $29.20 - $28.00

Jan ‘17 - Dec ‘17 $32.15 $30.30 - $29.30 $27.10 - $26.10 $26.10 - $25.00

Jan ‘18 - Dec ‘18 $31.30 $29.50 - $28.50 $26.40 - $25.40 $25.40 - $24.40

Electricity - Mass Hub

ATC 6/6/2016

Conservative (Low Risk)

Moderate (Medium Risk)

Aggressive(High Risk)

July ‘16 $32.05 $30.50 - $29.20 $29.20 - $27.90 $27.20 - $26.00

Aug ‘16 $31.90 $29.50 - $28.30 $28.30 - $27.00 $26.40 - $25.10

Sep ‘16 $26.35 $24.10 - $23.10 $23.10 - $22.00 $21.50 - $20.50

Oct ‘16 $25.65 $22.70 - $21.80 $21.80 - $20.80 $20.30 - $19.40

July ‘16 - Oct ‘16 $29.00 $26.60 - $25.50 $25.50 - $24.40 $23.80 - $22.70

Nov ‘16 - Mar ‘17 $53.60 $49.90 - $48.20 $44.70 - $42.90 $42.90 - $41.20

Jan ‘17 - Dec ‘17 $40.15 $37.90 - $36.60 $33.90 - $32.60 $32.60 - $31.20

Jan ‘18 - Dec ‘18 $40.40 $38.10 - $36.80 $34.10 - $32.80 $32.80 - $31.40

Source: Bloomberg Finance L.P.

JUNE 2016eforecaster

18

ELECTRICITY

EIA Short Term Energy Outlook Report 5/10/16(http://www.eia.gov/emeu/steo/pub/contents.html)

Report SummaryUnless noted, the following text is taken directly from the monthly EIA Short Term Energy Outlook Report (link to full report listed above)

ElectricityWholesale electricity prices this past winter (October through March) were significantly lower than in the winter of 2014-15. Day-ahead peak power prices averaged $35 per megawatthour (MWh) during winter 2015-16 in the wholesale market for the independent system operator (ISO) of New England, which was 52% below the average peak price during the 2014-15 winter. In the Electricity Reliability Council of Texas (ERCOT) ISO, peak wholesale prices averaged $21/MWh this past winter, a 36% decline from the previous winter. Mild winter temperatures along with low natural gas prices contributed to the lower wholesale electricity prices.

U.S. Electricity Consumption

U.S. temperatures during summer 2016, as measured by cooling degree days, are forecast to be close to last summer’s level, but 3% higher than the 10-year average. However, regional variations are expected. Forecast cooling degree days in the Pacific states in summer 2016 are 11% lower than in 2015, while cooling degree days in the East North Central states are expected to be 12% higher than in 2015. These regional differences in the level of cooling contribute to flat growth in summer residential electricity sales and 1.5% summer-over-summer growth in commercial electricity sales. U.S. Electricity Generation

Total U.S. electricity generation in 2016 is expected to average 11.2 terawatthours per day, slightly below the amount of electricity generated in 2015. Forecast total U.S. generation increases by 1.6% in 2017. EIA expects 34.0% of total electricity will be generated by natural gas in 2016, up from 32.7% last year. The projected share of coal-fired generation averages 30.5% in 2016, down from 33.2% last year. This would be the first year in which the annual generation share for natural gas exceeds that for coal. Coal is forecast to regain some of its generation share in 2017, as forecast natural gas prices slowly rise, but the forecast share of coal generation (31.4%) in 2017 remains below that of natural gas generation (32.9%).

U.S. Electricity Retail Prices

EIA expects the U.S. average retail price of electricity for the residential sector in May will average 12.9 cents per kilowatthour (kWh), with 18.5 cents/kWh in New England as the highest price and 11.1 cents/kWh in the East South Central region as the lowestprice. The U.S. residential electricity price averaged 12.7 cents/kWh in 2015 and is expected to fall by 0.7% to 12.6 cents/kWh in 2016 and then rise 2.4% to 12.9 cents/kWh in 2017.

Electricity and Heat Generation from Renewables

EIA expects total renewables used in the electric power sector to increase by 11.3% in 2016 and by 4.4% in 2017. Forecast hydropower generation in the electric power sector increases by 9.1% in 2016 and then falls by 0.6% in 2017. Generation from renewables other than hydropower is forecast to grow by 13.3% in 2016 and by 8.6% in 2017.

EIA expects that from 2015 to 2017, utility-scale solar photovoltaic (PV) capacity will grow by more than 13 gigawatts (GW). States leading in utility-scale solar capacity additions are California, Nevada, North Carolina, Texas, and Georgia. According to EIA’s Electric Power Monthly, in 2015 electricity generation from utility-scale PV exceeded generation from wind in California for the first time. Forecast utility-scale solar power generation averages 1.1% of total U.S. electricity generation in 2017.

Wind capacity, which starts from a significantly larger installed capacity base than solar, grew by 12% in 2015, and it is forecast to increase by 9% in 2016 and by 10% in 2017. In 2017, wind generation accounts for almost 6% of total generation.

Coal Supply

EIA estimates that U.S. coal production in April was 46 million short tons (MMst), a 6 MMst (12%) decrease from the previous month and 29 MMst (38%) lower than in April 2015. Forecast coal production is expected to decrease by 150 MMst (17%) in 2016, which would be the

JUNE 2016eforecaster

19

largest decline in terms of both tons and percentage since data collection started in 1949. In 2016, forecast coal production in the Appalachian region and Western region declines by 15% and by 20%, respectively. Interior region production declines by 9%. In 2017, total U.S. coal production is expected to increase by 32 MMst (4%).

According to the most recent data, electric power sector coal stockpiles were 189 MMst in February, nearly unchanged from January. This pattern deviates from the normal seasonal pattern where stockpiles decrease during the winter months. U.S. end-of-February coal stockpiles were still at high levels, despite the coal plant retirements that have occurred in recent months. This year, February stocks were 26% (39 MMst) higher than the February 2015 level. Coal ConsumptionCoal consumption in the electric power sector, which accounts for more than 90% of total U.S. coal consumption, is forecast to decline by 58 MMst (8%) in 2016. The decline is a result of competition with low-priced natural gas and from warmer-than-normal winter weather that reduced overall electricity generation. Coal consumption in the electric power sector is forecast to increase by 25 MMst (4%) in 2017, primarily because of rising natural gas prices.

Retirements of coal-fired power plants reduce coal-fired generation capacity in the forecast period, primarily in 2016. The retirements are the result of increased competition with natural gas generation and the industry response to the implementation of the Environmental Protection Agency’s (EPA) Mercury and Air Toxics Standards (MATS). In April, EPA granted units at five power plants an additional one-year extension to comply with MATS. These power plants will continue to operate while emission controls are installed or until reliable alternative generation sources are made available. Coal TradeSlower growth in global coal demand and lower international coal prices have contributed to a decline in U.S. coal exports. Lower mining costs, cheaper transportation costs, and favorable exchange rates are expected to continue to provide an advantage to mines in other major coal-exporting countries compared with U.S. producers. Coal exports in February were 5 MMst, up 2% from January but 31% lower than the amount exported in February 2015. EIA forecasts U.S. coal exports to decline by 15 MMst (20%) in 2016 and by 3 MMst (4%) in 2017. Atlantic and Gulf Coast power generators are forecast to maintain their current levels of coal imports, which are primarily from Latin America. Imports are projected to total about 11 MMst in 2016 and 2017. Coal Prices

EIA estimates the delivered coal price averaged $2.23/MMBtu in 2015. Forecast prices are $2.18/MMBtu in 2016 and $2.21/MMBtu in 2017.

ELECTRICITY

JUNE 2016eforecaster

20

ELECTRICITY

End EIA Short Term Energy Outlook Report Excerpt.

JUNE 2016eforecaster

21

Regulatory UpdatePJM

PJM’s capacity market for delivery during the capacity year June 2019 through May 2020 cleared at a substantial discount to 2018/2019 price levels – the eastern zone (EMAAC) cleared at a 47% discount ($119/MWday), while the rest of system price cleared at a 39% discount ($100/MWday).  The only area with price support year over year was ComEd (Chicago area) which cleared at a 6% discount ($202/MWday). The results are surprising given the increased penalty risk for cleared capacity resources that resulted from PJM’s “Capacity Performance” market reforms. Those reforms require that capacity resources be available during key high electric usage hours, or face substantial penalties that, in the extreme, can cause a resource to owe money to PJM in excess of their capacity revenues.

The results indicate that generators are setting offers to sell capacity to PJM based on fixed operating costs that are not covered by energy market revenues, or as price takers (to ensure they clear), rather than factoring in the penalty risk as PJM had anticipated would be the case.  A number of generation owners have publicly announced that portions of their fleet did not clear the capacity auction. The next steps for the owners of uncleared generation are still somewhat uncertain but could include retiring the generators, particularly for those facilities with high fixed operating costs like nuclear and coal. These generation owners are likely to press PJM for further capacity market reforms to try to increase prices to a level that supports these facilities.

For customers this means that the feared substantial capacity price increases that some anticipated would result from the Capacity Performance reforms are not taking shape, and that capacity costs, at least through 2019/2020, will remain in line with historic levels.

ELECTRICITY

Link to PJM Monthly Inside Lines Report

NYISO There were no significant changes during the prior month.

Link to NYISO Website

Link to NYISO Monthly Operations Report

Click here for link to PJM Capacity Market website and FAQ’s

ISO-NE There were no significant changes during the prior month.

Link to ISO-NE Website

Link to IS0-NE Monthly Operations Report

JUNE 2016eforecaster

22

Regulatory Update (continued) ELECTRICITY

MISO Work continues on a three-year forward capacity auction model for the Retail Choice portions of the MISO footprint.

That includes downstate Illinois as well as the bulk of the Lower Peninsula of Michigan. MISO is proposing a model similar to PJM’s, without the capacity performance piece. That would include a downward sloping demand curve. The Market Monitor isn’t pleased with the proposal due to the rather small scope of what capacity zones it would apply to. The MISO Board of Directors has instructed MISO Staff to conduct some analysis to show that there will be cost benefits to customers if such a proposal is adopted. MISO is hoping to get a final construct through the stakeholder and Board approval process by the beginning of July.

Link to MISO Website

Renewables/REC UpdatePlease click here to review Renewable data on the Direct Energy website

7 Things to Know About the Solar Tax Credit Extension

Please click here to review SRECTrade website

JUNE 2016eforecaster

23

ELECTRICITY

Regional Greenhouse Gas Initiative (RGGI)Link to Regional Greenhouse Gas Initiative Link to website Database of State Incentives for Renewables & Efficiency

Link to website National Renewable Energy Laboratory

NYISO Capacity:

Link to NYISO Monthly Auction Data

JUNE 2016eforecaster

24

ELECTRICITY

General News UpdateLow Natural Gas Prices, Increasing Power Plant Efficiencies and Renewables Taking a Toll on Nuclear Power Generation in MISO/PJM“CHICAGO (June 2, 2016) — Exelon Corporation today announced it will move forward to shut down the Clinton and Quad Cities nuclear plants, given the lack of progress on Illinois energy legislation.

The Clinton Power Station in Clinton, Ill., will close on June 1, 2017, and the Quad Cities Generating Station in Cordova, Ill., will close on June 1, 2018. Quad Cities and Clinton have lost a combined $800 million in the past seven years, despite being two of Exelon’s best-performing plants.”

Excerpt Exelon Press Release 06/02/2016

Energy Price Update

25

About Direct Energy BusinessDirect Energy Business is part of the largest retail energy supplier in North America and a champion in serving businesses’ diverse energy needs. Our leadership position, deep expertise and commitment to addressing our customers’ unique energy demands is how we’ve earned the trust of our customers and helped to make their businesses better.

With more than 25 years of industry experience, we are dedicated to helping companies make smart energy choices for their business. Contact us today to discuss your energy needs and we’ll help you navigate the opportunities available to your service location(s).

Copyright © 2016 Direct Energy Business. Direct Energy® and the Energy Bolt Design are either registered trademarks or trademarks of Direct Energy Marketing Limited in the United States and/or Canada used under license.

District of Columbia License No. EA-04-4-4. Maryland License Nos. IR-437; IR-719; IR-791. Texas PUCT Cert. No. 10011.

Direct Energy Business Commodity DeskPhone: 732.516.7550 Fax: 866.421.2451 Email: trigger@directenergy.com

Acknowledgements: The recipient acknowledges that he/she has made its own independent decisions and that Direct Energy Business is not acting as a fiduciary, agent, financial, investment or commodity trading advisor for it in connection with the negotiation and execution of any transaction, nor will any communication (written or oral) received from Direct Energy Business be deemed to be an assurance or guarantee as to any results expected from executing any transaction.

DEB00994

Disclaimer:The information presented in these pages was gathered and compiled by Direct Energy Business for the convenience of its employees, clients, and potential customers and is for informational purposes only. Direct Energy Business makes no claim to the accuracy, reliability, comprehensiveness or currency of the aforementioned data. All information is provided “as is” and is not intended for trading purposes or advice. As a viewer of this document, you acknowledge that you have no right to use or rely upon the information contained within for the purpose of any claims, demands, and/or actions (legal or otherwise). Direct Energy Business and its licensors retain all intellectual property rights to all information displayed on these pages and/or transmitted by email. Contents therein may not be reproduced, re-transmitted, or re-distributed without the express written consent of Direct Energy Business.