Q4 2016 Real-Time Call Brief

Highlights

To remind everyone, our premium well is one that earns a minimum of 30% after-tax rate of return with flat $40 oil and $2.50 gas prices on a direct basis.

We set the minimum at 30% to ensure that fully loaded well returns are accretive to corporate returns.

Going forward, EOG's capital will be focused on wells that are profitable at $40, meaning with modest increases to oil price, our returns have the potential to soar.

Our shift to premium drilling and improvements in operating costs resulted in record low finding cost of $5.22 per BOE when you exclude revisions due to commodity price.

Over the course of the year, we increased our premium drilling inventory nearly 9% to 6,000 locations and over 5 billion barrels of oil equivalent.

The company added 3.7 billion barrels of oil equivalent of new drilling potential in the Delaware Basin.

Since the downturn began in late 2014, we slashed unit operating costs by 22%.

Transforming EOG into a premium-only driller means we expect to deliver 18% oil growth within cash flow during 2017.

Remarkably, EOG can deliver strong 18% oil growth plus the dividend within cash flow if prices were to average $50 oil and $3 gas.

Our plan was finalized last month when strip prices were closer to $55 oil and $3.50 natural gas.

With our shift to premium drilling, our goal is to generate ROCE that exceeds our historical average of 13%.

At the start of 2016, our plan was to drill 200 and complete 270 net wells within cash flow for $2.5 billion.

By year end, due to our astonishing progress on cost control and efficiency gains, we drilled 280 and completed 445 net wells for $2.7 billion, all within cash flow. That's a 40% and 65% increase in drilling and completing activity with only an 8% increase in capital compared to our initial guidance.

Almost 60% of these completed wells were drilled but uncompleted wells, so we are beginning 2017 with our normal inventory of 137 DUCs.

Furthermore, our fourth quarter average oil rate of 312,000 barrels of oil per day set an all-time high from our previous record set in the fourth quarter of 2014.

Four significant sources of service cost savings in 2017 our average daily rig rates are down 25% compared to last year.

Fourteen of our drilling rigs or 60% of the total are under long-term contracts, and nine of these rigs are at bottom-of-market rates.

We've locked in three-quarters of our casing needs at prices 30% below our 2016 costs.

To further control cost, we've also locked in 50% of our frac fleets.

We have diverse sources of frac sand, and our aggregate sand costs are expected to decrease by 18% year over year.

We are drilling 20% longer laterals and increasing the use of multi-well pads.

Our expanded water infrastructure systems are expected to reduce our well cost by another $100,000 per well.

Because of the combination of operational efficiencies, we expect to complete 15% more wells per frac fleet this year.

During 2016, 210-day cumulative production improved 13% for wells drilled in our western acreage, while wells drilled in the east improved 10%.

We also reduced completed well cost by $1 million to $4.7 million, and believe further reductions are possible in 2017.

As with the 2015 pilots, the 32-well project delivered premium economics with a finding cost of less than $6 per barrel.

The results were favorable for wells completed from 2011 through 2016, with well spacing ranging from 200 feet to 500 feet.

The 300,000 barrels of net oil production from EOR in 2016 was within 5% of our forecast, further validating the consistency of the results observed in the four pilots prior to 2016. This data supports our previous estimates that the incremental recovery due to EOR is adding 30% to 70% more oil to our primary recovery estimates.

In 2017, we are eager to expand our EOR project by testing approximately 100 additional wells in six different areas.

Our technical capabilities combined with this transformative transaction resulted in adding a record-setting 3.7 billion barrels of oil equivalent of estimated resource potential last year alone.

In addition, we've already identified almost 3,500 premium oil locations across three targets in the Delaware, the Wolfcamp, the Second Bone Springs, and the Leonard.

In 2016, we completed 14 Austin Chalk wells with an average 30-day rate of 1,700 barrels of oil per day and total equivalent rate of 2,200 barrels of oil equivalent per day from an average lateral of 4,400 feet.

During 2017, we'll drill approximately 25 net wells in the Austin Chalk.

Our 2016 drilling program in this play averaged over 1,600 barrels of oil equivalent per day rate-restricted for the first 30 days and cost about $5 million to drill and complete.

Three Parkman wells had a 30-day rate that averaged 2,200 barrels of oil equivalent per day.

With the addition of the Yates acreage, our core position in the Powder River Basin has grown to 400,000 acres.

We are expanding this program in 2017 to complete 30 net wells.

We look forward to blocking up acreage, applying longer laterals, adding to our premium inventory, and exploring the 4,800 feet of stacked pay.

We expect to complete 35 net wells during 2017.

We replaced 163% of our 2016 production at a very low finding cost of $5.22 per BOE, excluding revisions due to commodity price changes.

The proved developed finding cost excluding leasehold capital was $6.50 per BOE.

As a result, our proved reserves increased by 1.4% year over year, driven by a 7.7% increase to crude oil and natural gas liquids reserves.

Capitalized interest for the fourth quarter of 2016 was $6 million.

Total exploration and development expenditures were $748 million, including facilities of $122 million excluding acquisitions and asset retirement obligations.

In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $31 million.

For the full year 2016, capitalized interest was $31 million.

2016 capital expenditures excluding acquisitions and asset retirement obligations were $2.7 million, in line with the updated guidance provide on last quarter's call. This amount includes facilities of $375 million and expenditures for gathering systems, processing plants and other property, plant, and equipment of $92 million.

Total discretionary cash flow was $2.75 billion.

In addition, proceeds from asset sales were $1.1 billion, which included natural gas assets in the Barnett Shale and Haynesville plays and marginal liquids plays in the Permian Basin and Rockies.

Total property acquisition costs other than Yates were $14 million for the year.

Capital additions related to the Yates transaction $3.1 billion of leasehold acquisitions; $735 million of proved property acquisitions; and $17 million of other property, plant, and equipment.

We also recorded $1.1 billion of deferred taxes related to the transaction.

To fund the Yates transaction, EOG issued 25 million shares of common stock and paid cash of $16 million for a total consideration of $2.4 billion.

At year end, total debt outstanding was $7 billion, for a debt to total capitalization ratio of 32%.

Considering $1.6 billion of cash on hand at year end, net debt to total cap was 28%.

In the fourth quarter 2016, total impairments were $298 million.

For the full year 2016, total impairments were $620 million.

Impairments to proved properties of $116 million were primarily the result of a write-down to fair value of legacy natural gas assets, which have since been divested.

The effective tax rate for the fourth quarter was 27% and deferred tax ratio was 44%.

Our 2017 CapEx estimate is $3.7 billion to $4.1 billion excluding acquisitions.

The exploration and development portion excluding facilities will account for about 81% of the total CapEx budget.

The budget for exploration and development facilities and gathering, processing, and other accounts for approximately 19% of the total CapEx budget for 2017.

We are committed to delivering industry-leading oil growth and returns and delivering this within cash flow, including dividends, even in a flat $50 oil environment.