Q4 2016 Real-Time Call Brief

Highlights

Cabot Group reduction improved reserve about 4% and 5% respectively from a capital program that was over 50% lower than 2015.

Our continued emphasis on cost control was demonstrated by our record low all source finding cost of $0.37 per Mcfe and our 11% year-over-year reduction in cash operating spends per unit.

Balance sheet remains strong with approximately $500 million of cash on hand and approximately $1.7 billion of available commitments on our undrawn credit facility.

During the year, we reduced our debt outstanding by almost $500 million by utilizing a portion of the proceeds from our equity issuance in early 2016 resulting in a significant reduction in leverage metrics throughout the year.

On the operational front, we announced an increase in our Marcellus EUR to 4.4 Bcf per 1,000 feet of lateral.

Now let's move to Slide 4, where we have highlighted our production and reserve growth over the last few years. You can see that we have averaged a 15% and 16% compounded annual growth rate for production reserves respectively over the last three years.

While our 2017 production growth guidance of 5% to 10% a slightly below our historic growth rate as we await new takeaway capacity in the Marcellus we are forecasting discretionary cash-flow cash flow to double this year based on recent strip prices which is driven by significant improvement in cash margins due to higher realized prices and lower operating cost.

As we highlighted in the press release this morning, we have increased our total program spending for the year from $625 million to $720 million which includes an $85 million increase for additional Eagle Ford activity to capitalize on the higher prices and most importantly improved well productivity, a $20 million increase in equity pipeline investments driven by a more favorable outlook on the construction timing for Atlantic Sunrise, and a $15 million increase in the Marcellus primarily for additional drilling activity driven by faster drilling times. These increases in capital are offset by approximately $25 million of savings from additional Marcellus drilling efficiencies.

We plan to spend $610 million of drilling completion and facility capital in 2017 of which 67% will go to the Marcellus and 33% will go to the Eagle Ford. This will fund the drilling and completion of approximately 90 net wells.

We plan to exist exit 2017 with 45 ducts of which 35 are located in the Marcellus positioning us well for accelerating production growth in 2018 upon the in service of new takeaway capacity.

Despite an increase in capital spending, we are currently forecasting approximately $250 million of positive free cash flow for the year based on strip prices.

While our production growth guidance of 5% to 10% remains unchanged, our year-over-year oil growth guidance of 15% is substantially higher than the zero percent oil growth contained in our original budget.

On the left side of slide 11 we highlight the impact of our enhanced completions on our Eagle Ford returns. At today's well cost our average 9,000 foot lateral generates a rate of return of over 60% at a $50 per barrel realized price which is about what we are realizing currently.

You can see that even when assuming inflationary pressure on well costs, our returns are still above 45%.

We anticipate growing our exit oil volumes this year by 50% as opposed to the 5% we forecasted in the original budget.

Heading over the Marcellus and turning to Slide 12, we applauded the average cumulative production results for our Gen 4 completions compared to our prior tight curves of 3.8 Bcf per 1,000 feet and our new type curve of 4.4 Bcf per 1,000 feet.

While our sample size is still limited with only 21 wells based on production data we have to-date and the fact that these 21 wells were drill drilled in the north, south, east, and west, we are very confident that these results are repeatable across the field.

While it is very well understood across the industry and investment community that Cabot's wells in Northeast Pennsylvania are some of the best wells in the country, slide 13 illustrates how our EUR stacks up against other natural gas operating areas across the US. In fact our 4.4 Bcf per 1,000 feet is double of some of our peers who have been touting their technical expertise on the completion front.

Slide 14 demonstrates how our increasing EURs, our improvements in well cost and better realized pricing are impacting our economics. We originally budgeted $7.9 million for a 8,000-foot lateral Gen 4 well cost back in October of last year. However, we are currently averaging about 10% lower due to improved operating efficiencies. Approximately 75% of our cost are locked-in under term contracts so we are anticipating only a slight increase in well cost by year-end.

Our marketing team continues to identify new find new opportunities to increase Cabot's gross trajectory out of the Marcellus as evidenced through addition of a new 3-year sales contract of 150 million per day on Atlantic Sunrise that was announced at the end of last year.

For 2017 36% of our volumes are locked-in under fixed-price contracts at a weighted average price of $2.29 per Mcf which implies a rate of return greater than 150% for our typical Marcellus well.