Q OPERATIONS REPORT May 5, 2015

Transcription

1 Q OPERATIONS REPORT May 5, 2015 NYSE: DVN devonenergy.com Howard J. Thill Senior Vice President, Communications and Investor Relations Scott Coody Director, Investor Relations IR Contacts Shea Snyder Director, Investor Communications Table of Contents Q1 Results Overview & Outlook... 3 Operating Areas: Eagle Ford.. 6 Permian Basin... 9 Heavy Oil. 13 Anadarko Basin.. 15 Barnett Shale Rockies Oil

2 INVESTOR NOTICES Forward Looking Statements Some of the information provided in this report includes forward looking statements as defined by the United States Securities and Exchange Commission (SEC). Forward looking statements are often identified by use of the words forecasts, projections, estimates, plans, expectations, targets, opportunities, potential, outlook and other similar terminology. Such statements concerning future performance or events are subject to a variety of risks and uncertainties that could cause actual results to differ materially from the forward looking statements contained herein. Certain risks and uncertainties are described in more detail at the end of this report as well as in the Risk Factors section of our most recent Form 10 K and under the caption Forward Looking Statements in the related earnings release included as an exhibit to our Form 8 K furnished May 5, Cautionary Note to Investors The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This presentation may contain certain terms, such as resource potential and exploration target size. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10 K, available from us at Devon Energy Corporation, Attn: Investor Relations, 333 West Sheridan, Oklahoma City, OK You can also obtain this form from the SEC by calling SEC 0330 or from the SEC s website at Q OPERATIONS REPORT 2

3 Q1 RESULTS OVERVIEW & OUTLOOK Production Exceeds Guidance for 3 rd Consecutive Quarter Overall, total production from Devon s retained asset base increased 22% year over year to 685,000 Boe per day. Excellent execution across the portfolio drove top line production to exceed the upper end of the company s guidance range by 12,000 Boe per day. The company s high quality assets in many of North America s best resource plays, combined with a focused effort to deliver superior execution, have exceeded the top end of production guidance for 3 consecutive quarters. Oil production averaged 272,000 barrels per day, also exceeding the top end of guidance by 12,000 barrels per day. This is the highest average daily oil rate in company history and represents a growth rate of 55% compared to the first quarter of 2014 (chart below). TOTAL COMPANY Q1 STATS * Q Q Production: Oil (MBOD) NGL (MBLD) Gas (MMCFD) 1,645 1,607 MBOED E&P Capital (in millions): $1,326 Operated Rigs (at 3/31/15): 30 * Excludes non core divested assets. Heavy Oil The most significant growth came from Devon s U.S. operations, where oil production increased 72% year over year. This substantial oil growth is attributable to Devon s Eagle Ford and Delaware Basin operations. 176 Q1 Oil Production (1) (MBOD) 55% Growth 272 Q1 Production Mix 40% 40% 20% Rockies Oil Anadarko Basin Q Q U.S. Canada (1) Excludes non core divested assets. Oil NGL Gas Devon also achieved strong oil production growth from its heavy oil operations in Canada. Driven by the ramp up of its Jackfish 3 facility, Canadian net oil production increased 33% compared to the year ago quarter. Permian Basin Eagle Ford Oil Assets Liquids Rich Gas Assets Barnett Shale Q OPERATIONS REPORT 3

4 Q1 RESULTS OVERVIEW & OUTLOOK Production Exceeds Guidance for 3 rd Consecutive Quarter (continued) With this strong growth in oil production, the company s liquids volumes now account for 60% of its production mix (chart page 3). Cost Reduction Initiatives Delivering Excellent Results First quarter results were positively impacted by the company s cost reduction initiatives that focus on capturing the full value of every barrel produced. The most significant cost savings were realized within lease operating expenses (LOE), the company s largest field level cost. First quarter LOE per Boe declined 7% year over year to $8.97 and was 7% below the low end of the guidance range. The reduction in LOE is even more impressive given the company s substantial oil production growth, which typically has higher operating costs than natural gas production. Based on year to date cost savings, Devon now expects the midpoint of its 2015 LOE guidance to decline to around $9.30 per Boe. Compared to the company s previous guidance, this implies a full year cash cost savings of around $170 million (chart below). $10.00 Previous Guidance 2015e LOE Guidance (Using Midpoint, $/BOE) $170 MM Cash Cost Savings $9.30 Revised Guidance Midstream Update: The EnLink Advantage The company had another strong quarter operationally from its marketing and midstream business. First quarter operating profit reached $193 million, a 6% increase from the first quarter of On March 23, 2015, the company announced its initial asset dropdown to EnLink Midstream Partners (NYSE: ENLK) with the sale of the Victoria Express Pipeline (VEX) in the Eagle Ford. Total consideration for this highly accretive transaction was approximately $215 million or 10 times estimated 2015 EBITDA. Also in March, Devon commenced a secondary offering and sold 22.8 million ENLK partnership units. The offering settled late in Q1, with the company realizing cash proceeds of about $570 million. Subsequent to quarter end, the underwriters exercised their 30 day option to purchase an additional 3.4 million ENLK partnership units resulting in $85 million of incremental cash proceeds to Devon (table below). Recent Midstream Transactions Value ($MM) VEX Dropdown $215 Secondary Offering $655 * Total $870 * Includes exercised underwriter option Devon s Retained Ownership Market Value ($B) ENLK (95 MM Units) $2.4 ENLC (115 MM Units) $4.1 DVN s Ownership $6.5 As of 5/1/15 With the completion of the secondary offering, Devon now has a 32% interest in ENLK and a 70% ownership in the EnLink general partner (NYSE:ENLC). In aggregate, Devon s retained ownership interest in EnLink is valued at approximately $6.5 billion (table above). Q OPERATIONS REPORT 4

5 Q1 RESULTS OVERVIEW & OUTLOOK Raising 2015 Production Outlook Based on the strong results achieved in Q1 and the expectation of continued operational momentum, Devon has raised its 2015 production outlook. Total oil production growth in 2015 is now expected to range from 25% to 35%, a substantial increase from the company s previous full year growth guidance of 20% to 25% (chart below). 2015e Oil Production Guidance 255 Previous Guidance (Using Midpoint, MBOD) +15 MBOD The majority of this incremental oil production growth is expected to come from Devon s U.S. asset base, where the company s Eagle Ford and Delaware Basin assets continue to deliver substantial per well productivity gains. Due to the improving outlook for oil production, Devon has also raised its topline production growth guidance in 2015 to a range of 5% to 10% (table below). 270 Revised Guidance Revised 2015 Capital Outlook: Additional Cost Savings Achieved In addition to higher production volumes, the company is also benefiting from lower capital requirements. Devon s 2015 E&P capital program is now expected to range from $3.9 to $4.1 billion. This represents a $250 million reduction in capital spending compared to the company s previous guidance issued in mid February (table below). REVISED 2015 CAPITAL PREVIOUS GUIDANCE ($MM) REVISED GUIDANCE ($MM) REDUCTION ($MM) 2015 E&P Capital $4,100 $4,400 $3,900 $4,100 $250 The $250 million reduction of E&P capital is due to the acceleration of service cost savings and capital efficiencies achieved across Devon s portfolio. In aggregate, the lower capital requirements ( $250 million), improved LOE outlook ( $170 million), and accretive midstream transactions ( $870 million), have further boosted the company s excellent financial strength and liquidity. REVISED 2015 PRODUCTION 2014 ACTUAL 2015 REVISED GUIDANCE YOY GROWTH (Using Midpoint) Oil & Bitumen (MBOD) % NGL (MBLD) (1%) Gas (MMCFD) 1,685 1,595 (5%) MBOED % Q OPERATIONS REPORT 5

6 EAGLE FORD Net production averaged a record 122,000 Boe per day in the first quarter with oil accounting for 62% of total production. This strong result represents a 23% increase in production compared to the fourth quarter and nearly 140% increase in production compared to Devon s first month of ownership in March 2014 (chart below). 51 Eagle Ford Production Growth (MBOED) 140% Increase 122 March 2014 Q2 Q3 Q4 Q This prolific Eagle Ford production is also achieving the lowest per unit operating costs of any asset in the company s portfolio. First quarter LOE totaled $4.54 per Boe, a decline of 8% year over year. World Class Development Results in DeWitt The company s world class oil development in DeWitt County continued to deliver some of the highest rate of return wells in North America in Q1. The company added 79 new Lower Eagle Ford wells to production during the quarter. Initial 30 day production rates from these wells averaged almost 2,100 Boe per day, of which approximately 70% was oil. EAGLE FORD Q1 STATS Q Q Production: Oil (MBOD) NGL (MBLD) 23 3 Gas (MMCFD) MBOED E&P Capital (in millions): $382 Operated Rigs (at 3/31/15): 1 (11 including JV rigs) Devon s new well activity in the Lower Eagle Ford in DeWitt County was highlighted by several high rate wells with 30 day IP rates in excess of 3,000 Boe per day (table below). Well Name Notable Eagle Ford Wells DeWitt County 24 Hr IP BOED 30 Day IP BOED %Oil Hansen B Oliver D SA 2H 4,110 3,590 73% Oliver A 9H 3,800 3,270 68% Hansen A 4H 3,750 3,240 69% Oliver A 7H 4,470 3,210 68% Hansen B Oliver D SA 1H 4,270 3,200 76% Q OPERATIONS REPORT 6

7 EAGLE FORD Productivity Gains Boost DeWitt Results The high rate wells brought online in DeWitt County during the first quarter represent more than an 80% increase in 30 day IP rates compared to the company s first month of ownership in March This increase in per well productivity is attributable to recent completion design improvements and better production operations management. DeWitt 30 Day IP Growth (MBOED) 2,070 To date, Devon s Upper Eagle Ford activity is highlighted by 4operated wells across both DeWitt and Lavaca counties (map below). Initial 30 day production rates from these wells averaged 1,000 Boe per day. With additional geologic modeling and further completion design enhancements, the company believes there is upside to these results. Devon has identified 450 unrisked locations in the Upper Eagle Ford play and the company will continue to appraise this emerging opportunity with 3 additional tests in ,120 >80% Growth March 2014 Q In an effort to generate greater fracture complexity and higher stimulated rock volume, the company s enhanced completion design is utilizing particulate diverters and higher concentrations of 100 mesh sand. Also contributing to these outstanding results is Devon s production optimization program. This initiative is improving production rates through an engineered approach that analyzes well performance data and tailors a unique plan to manage well pressure and maximize value for each well. Encouraging Eagle Ford Appraisal Results In the first quarter, the company brought online its first operated Upper Eagle Ford well in DeWitt County. The Pargmann 1H achieved an average 30 day production rate of nearly 1,600 Boe per day (map right). Also during the quarter, the company continued to appraise the Lower Eagle Ford on its Lavaca County acreage. Drilling activity was highlighted by 3 wells that had initial 30 day rates in excess of 1,100 Boe per day. Q OPERATIONS REPORT 7

8 EAGLE FORD Q2 Production Outlook Based on strong Q1 production results, Devon is ahead of its full year plan in the Eagle Ford. Due to the prolific improvements in well productivity in DeWitt County, the company expects to reach field takeaway capacity in the upcoming quarter. Devon and its partner are currently working on debottlenecking takeaway capacity. These constraints are expected to limit the company s Eagle Ford production in the second quarter to a range of 115,000 to 125,000 Boe per day. This outlook implies a year over year growth rate of roughly 85% (chart below). Q2 Expected Eagle Ford Production (MBOED) % Expected Growth Q Q2 2015e Q OPERATIONS REPORT 8

9 PERMIAN BASIN Net production averaged a record 102,000 Boe per day, a 12% increase compared to the first quarter of In aggregate, winter weather events curtailed production by approximately 3,000 Boe per day in the first quarter. Delaware Basin Drives Permian Performance Permian Basin production growth was driven almost entirely by light oil production from the company s Delaware Basin assets. Total Delaware Basin production averaged 53,000 Boe per day in the first quarter, 15% higher than the fourth quarter of PERMIAN BASIN Q1 STATS Q Q Production: Oil (MBOD) NGL (MBLD) Gas (MMCFD) MBOED E&P Capital (in millions): $445 Operated Rigs (at 3/31/15): 15 Since 2010, the company has increased its Delaware Basin production nearly 250% or approximately 35% compounded annually. Delaware Basin Activity Focused on Bone Spring Play The company is running 13 operated rigs in the Delaware Basin developing highly economic opportunities across Southeast New Mexico (map right). Approximately 75% of this rig activity is targeting Bone Spring intervals in the basin, which is characterized by deeper, over pressured reservoir with more contiguous pay zones. These high impact wells are delivering some of the best returns in Devon s portfolio. The remaining rig activity is developing economically attractive Bone Spring opportunities on the slope. The channelized Bone Spring sands on the slope are generally lower cost than the basin due to shallower, more normalized pressures. Q OPERATIONS REPORT 9

10 PERMIAN BASIN Delaware Basin Activity Focused on Bone Spring Play (continued) 180 Day Cumulative Production Bone Spring Basin First quarter drilling activity in the Delaware Basin was highlighted by 22 new Bone Spring wells that utilized an enhanced completion design. Of these wells, 16 were drilled in the basin and 6 on the slope. Initial 30 day production rates from the 16 Bone Spring basin wells averaged approximately 1,200 Boe per day, with the 6 Bone Spring slope wells averaging nearly 600 Boe per day. An improved completion design drove these outstanding results. The average sand volume for these Q1 development wells increased to 1,900 pounds per lateral foot, with a few wells testing up to 3,000 pounds. This compares to a historical design of around 600 pounds per lateral foot. Cumulative Production (MBOE) New Designs Old Design 60% Increase Days The company continues to monitor production from these enhanced completion designs and further optimize frac variables such as fluid types and volumes, as well as cluster and stage spacing. These learnings will be integrated into future development plans in the Delaware Basin. With Devon s extensive testing of enhanced completions across Southeast New Mexico, the company possesses an extensive knowledge base that can be utilized to optimize per well value in various commodity price and service cost environments. Enhanced Completion Design Raises Expectations for Bone Spring Basin The company has tested enhanced completion designs on more than 60 Bone Spring development wells since mid The majority of these tests have focused on the 2 nd Bone Spring interval in the basin (map page 9), where the company has achieved its best results. These enhanced completion tests in the basin have significantly improved initial production rates, EURs, and enhanced rates of return compared to the old design. On average, cumulative production per well has increased 60% over the first 180 days compared to wells with the old designs (chart above right). Based on strong results from the enhanced completion designs, Devon is raising type curve expectations in the Bone Spring basin for both initial production and EUR. IP rates are expected to be around 60% higher than wells with the old design with per well EURs expected to achieve around 600,000 Boe, up 33% from previous estimates (table/chart below) 30 Day IP BOED EUR MBOE Key Modeling Stats Oil / NGL % of Production % / 20% WI / NRI 71% / 56% Sand Pounds/Ft. 1,500 2,000 Bone Spring Basin Type Well 575 Old Old Design Completions 600 lbs./ft. 30 Day IP Rates (BOED) 60% Increase 900 New New Designs 1,500 Completions 2,000 lbs./ft. Q OPERATIONS REPORT 10

11 PERMIAN BASIN Optimizing Delaware Basin Development Plan Pilot 3 Pilot 4 Pilot 5 To optimize future development schemes and ultimately maximize the value of our resource, the company is conducting a number of Bone Spring downspacing pilots in the basin portion of Eddy and Lea counties during A portion of this activity will test tighter well spacing of 6 to 8 wells per section in the lower interval of the 2 nd Bone Spring, which is the company s traditional landing zone (pilots 1 and 2 below). 2 nd BONE SPRING Upper Lower , Planned Pilot Well Existing Producer 2 nd BONE SPRING Upper Lower Pilot 1 Pilot Planned Pilot Well Existing Producer 3 rd BONE SPRING Another planned pilot will test staggered laterals between the upper and lower 2 nd Bone Spring intervals with 280 foot spacing, as well as the deeper 3 rd Bone Spring potential (pilot 5 above). 50 These multiple pilot programs are now under way, with data collection and analysis occurring throughout the year and into In conjunction with the development of the lower portion of the 2 nd Bone Spring, Devon is also testing the commerciality of the upper interval. The company s first well in the upper 2 nd Bone Spring, the Boundary Raider 6 Federal 2H, continues to perform exceptionally well. In the first quarter, production from the Boundary Raider continued to improve upon its reported IP rate in Q4 achieving an impressive 30 day peak rate of 2,400 Boe per day. Devon recently commenced production on its second well with the upper portion of the 2 nd Bone Spring. Initial 30 day production from the Tomb Raider Fed 1H averaged around 1,500 Boe per day. These encouraging well results in the upper 2 nd Bone Spring highlight the opportunity to develop multiple intervals in the 2 nd Bone Spring where Devon is also testing staggered laterals between the upper and lower with 660 foot spacing ( 80 acre spacing) (pilots 3 and 4 above right). Downspacing Pilots Provide Upside to Delaware Basin Inventory With commercial success from Devon s downspacing program, the company s risked undrilled inventory from its prolific Bone Spring position has the potential to significantly increase. Formation Net Risked Acres Risked Wells Per Section Gross Risked Locations Delaware Sands 80, Leonard Shale 60, Bone Spring 285, ,500 Wolfcamp >100,000 N/A Evaluating Other (Yeso & Strawn) 20,000 4 >200 Gross Unrisked Locations Total >500,000 >5,000 >11,000 Q OPERATIONS REPORT 11

12 PERMIAN BASIN Midland Basin Delivers Capital Efficient Growth First quarter capital activity in the Midland Basin was centered on further developing its Southern Midland Wolfcamp joint venture area. In Q1, the company s joint venture partner funded 70% of Devon s capital requirements. Approximately $90 million of capital was invested in the Midland Basin during Q1 and the company has now fully utilized its joint venture drilling carry. Capital requirements for the remainder of the year are expected to be limited to less than $150 million. This capital efficient program delivered overall net production in the Midland Basin of 49,000 Boe per day during the quarter. This represents an increase of 3% compared to the first quarter of Maximizing Base Production in the Midland Basin Midland Basin operations for the remainder of the year will be focused on continuing the company s appraisal of Martin county, as well as maximizing base production through optimizing existing well performance. These optimization initiatives include remediation work on existing producers, artificial lift and minimizing downtime. Controllable production downtime in Q1 declined to less than 2%. Q OPERATIONS REPORT 12

13 HEAVY OIL Net oil production in Canada averaged 104,000 barrels per day, a 33% increase compared to the first quarter of 2014 (chart below). Additionally, unit LOE declined 34% over the same time period to $14.62 per barrel. 78 Heavy Oil Production (MBOD) 33% Growth Q Q Jackfish Complex Drives Q1 Performance 104 Jackfish 3 Jackfish 2 Jackfish 1 Lloydminster The strong performance was driven by Devon s Jackfish complex where gross production averaged a record 78,000 barrels per day. After adjusting for royalties, net production reached 76,700 barrels per day, a 48% increase compared to the first quarter of Since first production from Jackfish 1 in late 2007, Devon has produced 100 million barrels from the Jackfish complex. Over this time, heavy oil cash margins have been as high as $61 per barrel and averaged $34 per barrel (chart right). While current industry conditions are challenging, Devon s top tier heavy oil position delivered a positive cash margin of $7 per barrel in Q1. HEAVY OIL Q1 STATS Q Q Production: Oil & Bitumen (MBOD) NGL (MBLD) Gas (MMCFD) MBOED E&P Capital (in millions): $190 Operated Rigs (at 3/31/15): 2 $60 $50 $40 $30 $20 $10 Heavy Oil Cash Operating Margin $ Per Barrel Average: $34 Per Barrel $ Q Q OPERATIONS REPORT 13

14 HEAVY OIL Jackfish 1 Continues to Exceed Name Plate Capacity Gross production at Jackfish 1 averaged 35,200 barrels per day in the first quarter. Net production averaged 34,700 barrels per day, a 9% increase compared to the fourth quarter of Ongoing efforts to optimize steam efficiency and well productivity drove capacity utilization at Jackfish 1 to greater than 100% for the 5th straight quarter. Jackfish 2 Production Advances Gross production at Jackfish 2 averaged 28,200 barrels per day, a 13% increase compared to the first quarter of After royalties, net production totaled 27,600 barrels per day. Improved performance from existing well pads drove the strong Q1 production. The company plans to begin steaming a new well pad in the fourth quarter of The production contribution from this pad is expected to help Jackfish 2 achieve peak facility capacity in Jackfish 3 Delivering Significant Growth Gross production from Devon s newest thermal facility averaged 14,600 barrels per day. After royalties, net production was 14,300 barrels per day. Currently, gross production at Jackfish 3 is approximately 20,000 barrels per day. 1.7 Jackfish 3 Gross Production Ramp Up (MBOD) Devon expects to reach nameplate capacity of 35,000 barrels per day around year end Pike Winter Stratigraphic Drilling Complete Devon completed its stratigraphic drilling program at its Pike heavy oil project in the first quarter. Stratigraphic wells from the winter drilling program met or exceeded expectations. Roughly $50 million of Pike capital was spent in Q1. Capital requirements for the remainder of 2015 are expected to be limited to $100 million. The remaining activity at Pike in 2015 will consist of additional front end engineering work to optimize facility design and cost structure. Upon completion of the engineering work, expected in the fourth quarter of 2015, the company will review the go forward plan with Pike. Production Outlook Beginning in June, the company will bring its Jackfish 1 facility down for a scheduled 21 day maintenance period that was deferred from This maintenance downtime and subsequent ramp up at J1 is expected to curtail Q2 heavy oil production by approximately 10,000 barrels per day. As a result, Devon expects net oil production from its heavy oil operations to range between 95,000 and 100,000 barrels per day in the second quarter. The mid point of this forecast represents around a 25% growth rate compared to the second quarter of For the full year, heavy oil production remains ahead of the company s original budget expectations and it now expects 2015 production to range from 100,000 to 110,000 barrels per day. Q Q Q Current YE 2015 Q OPERATIONS REPORT 14

15 ANADARKO BASIN Net production averaged 88,000 Boe per day in the first quarter, with liquids production accounting for 44% of total production. Cana Woodford Development Activity Remains on Plan The Cana Woodford play was the most significant contributor to production in the Anadarko Basin averaging 66,000 Boe per day, a 13% increase compared to the year ago quarter. In the first quarter, no new operated Woodford development wells were brought online. With the recent ramp up of drilling activity and the utilization of pad drilling, completion operations are expected to commence mid year. For the year, Devon remains on plan to drill approximately 75 development wells in the Cana Woodford. This activity is focused on developing 70 acre well spacing in the liquids rich core. ANADARKO BASIN Q1 STATS Q Q Production: Oil (MBOD) 9 9 NGL (MBLD) Gas (MMCFD) MBOED E&P Capital (in millions): $132 Operated Rigs (at 3/31/15): 8 To further improve well productivity, Devon and its partner will test sand volumes ranging from 1,800 to as high as 2,400 pounds per lateral foot. Learnings from the larger completion tests will help further refine the company s Woodford completion design. Further Productivity Gains Expected at Cana Woodford Development Over the past year, the company has employed a new completion design on approximately 40 Cana Woodford wells. The improved design utilizes 1,200 pounds of sand per lateral foot (70% more than original design), twice the frac stages and tighter perf clusters. Initial 30 day production rates from these wells averaged around 1,300 Boe per day, a 40% increase compared to wells with the old design. And, EURs are also trending 30% higher than those with previous design. 920 Old Design 30 Day IP Rates (BOED) 40% Increase 1,300 New Design 2014 Program, 40 Wells Sand Pounds/Ft. Frac Stages Perf Clusters Old Design New Design 700 1,200 Testing 1,800 2, Q OPERATIONS REPORT 15

16 ANADARKO BASIN Emerging Meramec Potential Devon and its partner are running 3 rigs during 2015 to appraise its acreage in the emerging Meramec play. The Meramec formation sits above the Woodford Shale at a depth of around 8,000 to 10,000 feet (geologic column below). To date, the company has drilled or participated in 12 Meramec wells with at least 30 days of production history. Initial 30 day rates from these appraisal wells averaged approximately 1,500 Boe per day (table below). Devonian Mississippian Penn. MORROW SPRINGER CHESTER MERAMEC OSAGE WOODFORD HUNTON Acreage and Inventory Update 30 Day IP BOED EUR MBOE D&C Cost Liquids % of Production Meramec Type Well Key Modeling Stats 1,500 1,400 $8 MM 51% WI / NRI 34% / 28% LOE ($/BOE) $5 Devon will continue to derisk this emerging play throughout the year with plans to spud or participate in about 30 additional Meramec wells in The company s Cana Woodford position is the largest and best in the industry with 280,000 net acres (map right). This premier Woodford position has a risked inventory of about 3,600 undrilled locations (table right). Essentially all of Devon s Cana Woodford acreage has multi stack pay potential, with the most promising in the shallower Meramec formation. With the recent success of appraisal activity in the Meramec, the company has now derisked 60,000 net acres in the oil and liquids window of the play (map below), a 70% increase from previous estimates. Devon has identified more than 400 risked locations in the Meramec. The company expects its Meramec acreage and location count to trend higher with additional drilling success across the play. Combined, the Woodford and Meramec opportunities provide the company with 340,000 net acres and more than 4,000 locations to develop (table below). This drilling inventory is one of the deepest and most economic in the company s portfolio. Formation Meramec Window Net Risked Acres Oil and Liquids 60,000 >400 Dry Gas TBD TBD Gross Risked Locations Liquids Rich 200,000 2,300 Woodford Dry Gas 80,000 1,300 Total 340,000 >4,000 Q OPERATIONS REPORT 16

17 BARNETT SHALE Net production averaged 191,000 Boe per day, with liquids production accounting for 28% of total Barnett Shale production in the first quarter. Maximizing Base Production The company continues to focus on maximizing base production through optimizing existing well performance in this liquids rich gas play. Ongoing optimization efforts include a vertical refrac program, line pressure reduction initiatives and efforts to further reduce production downtime (controllable downtime was a company best at less than 1% in Q1). First quarter activity was highlighted by the strong results from the vertical refrac program. Devon re stimulated 50 wells during the quarter, with an average EUR uplift of approximately 70 MBoe per well (table right). These capital efficient vertical refracs cost less than $300,000 per well, roughly 25% less compared to the same activity a year ago. Low Cost Structure Boosts Margins The Barnett Shale is one of Devon s lowest cost assets with lease operating expense averaging only $5.75 per Boe in the first quarter. This low cost structure enabled cash operating margin to reach nearly 50% of revenue in the first quarter. In an effort to capture the full value of every Boe produced, the company has several cost reduction initiatives under way in the Barnett Shale. BARNETT SHALE Q1 STATS Q Q Production: Oil (MBOD) 1 2 NGL (MBLD) Gas (MMCFD) MBOED E&P Capital (in millions): $32 Operated Rigs (at 3/31/15): 0 Vertical Refracs Per Well Stats IP Uplift BOED EUR Uplift MBOE Cost <$300,000 IRR * >20% 2015 Plans 200 wells * Assumes $3/Mcf HH and fully burdened economics after tax. Q OPERATIONS REPORT 17

18 ROCKIES OIL Net production averaged 22,000 Boe per day in the first quarter. Oil production from this emerging opportunity increased 51% compared to the first quarter of 2014 (chart below). Raising Powder River Basin Type Curve Expectations 8 Rockies Oil Production (MBOD) 51% Growth Devon brought 11 development wells online during the quarter targeting the Parkman and Turner formations in Campbell County, Wyoming. Initial 30 day production rates from these wells averaged almost 1,400 Boe per day, of which more than 80% was light oil. A recently enhanced well design drove these outstanding results. The company s new design uses extended reach laterals of 9,600 feet, more than 2 times the lateral length of the previous design. With strong results from the well design changes, Devon is raising its type curve in the Parkman Focus Area. Initial 30 day production rates for these extended reach development wells are expected to be about 150% higher than the previous design, at an incremental cost of only 45% (table/chart right). 12 Q Q ROCKIES OIL Q1 STATS Q Q Production: Oil (MBOD) 12 8 NGL (MBLD) 1 1 Gas (MMCFD) MBOED E&P Capital (in millions): $111 Operated Rigs (at 3/31/15): 2 30 Day IP BOED EUR MBOE D&C Cost Oil / Gas % of Production Key Modeling Stats Parkman Focus Area Type Well 1, $8 MM 95% / 5% WI / NRI 58% / 46% LOE ($/BOE) $8 525 Previous 4,000 Lateral 30 Day IP Rates (BOED) 150% Increase 1,300 Extended Reach 9,600 Lateral Q OPERATIONS REPORT 18

19 ROCKIES OIL Opportunistic Acreage Capture With its improving potential in the Powder River oil fairway, the company has opportunistically added to its leasehold by acquiring an additional 42,000 net surface acres (map below). These leases are adjacent to Devon s acreage in the Parkman Focus Area and also expand its opportunity set across multiple formations in Campbell County. CO 2 Projects to Enhance Rockies Oil Growth Devon is currently in the process of bringing online its Big Sand Draw CO 2 facility in central Wyoming within the Wind River Basin. Start up from this enhanced recovery project is expected by mid Once operational, oil production is expected to ramp up to more than 5,000 barrels per day over the next 18 months and maintain a steady production profile for 20 years with minimal capital requirements. The company is investing approximately $100 million of start up related capital in the Big Sand Draw CO 2 facility during Devon has a 98% working interest and an 76% net revenue interest in this project. Combined with the company s Madison CO 2 facility, which is fully operational, production from the Wind River Basin is expected to increase to around 8,000 Boe per day in In total, Devon now has 225,000 net prospective acres in the Powder River oil fairway with potential in the Parkman, Turner and Frontier formations. With the success of the extended reach lateral program, the company now expects to more efficiently recover resource with fewer wells. Coupled with the recent acreage acquisitions, Devon has approximately 820 undrilled locations in its inventory (1,450 locations without the use of extended reach laterals). The Parkman formation accounts for approximately 55% of this total undrilled inventory. Q OPERATIONS REPORT 19

20 DISCUSSION OF RISK FACTORS Forward Looking Statements: Information provided in this report includes forward looking statements as defined by the Securities and Exchange Commission. Forward looking statements are often identified by use of the words forecasts, projections, estimates, plans, expectations, targets, opportunities, potential, outlook, and other similar terminology. Such statements are subject to a variety of risk factors. A discussion of risk factors that could cause Devon s actual results to differ materially from the forward looking statements contained herein are outlined below. The forward looking statements provided in this report are based on management s examination of historical operating trends, the information which was used to prepare reserve reports and other data in Devon s possession or available from third parties. Devon cautions that its future oil, natural gas and NGL production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development, production and sale of oil, gas and NGL. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmental risks, drilling risks, political changes, changes in laws or regulations, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks identified inourform10 K and our other filings with the SEC. Specific Assumptions and Risks Related to Price and Production Estimates: A significant and prolonged deterioration in market conditions and the other assumptions on which our estimates are based will impact many aspects of our business and our results. Substantially all of Devon s revenues are attributable to sales, processing and transportation of three commodities: oil, natural gas and NGL. Prices for oil, natural gas and NGL are determined primarily by prevailing market conditions, which may be impacted by a variety of general and specific factors that are difficult to control or predict. Worldwide and regional economic conditions, weather and other local market conditions influence the supply of and demand for energy commodities. In particular, concerns about the level of global crude oil and natural gas inventories and the production trends of significant oil producers like OPEC, among other things, have led to a significant drop in prices. In addition to volatility from general market conditions, Devon s oil, natural gas and NGL prices may vary considerably due to factors specific to Devon, such as pricing differentials among the various regional markets in which our products are sold, the value derivable from the quality of oil Devon produces (i.e., sweet crude versus heavy or sour crude), the Btu content of gas produced, the availability and capacity of transportation facilities we may utilize, and the costs and demand for the various products derived from oil, natural gas and NGL. Estimates for Devon s future production of oil, natural gas and NGL are based on the assumption that market demand and prices for oil, natural gas and NGL willbe at levels that allow for profitable production of these products. As illustrated by recent market trends, there can be no assurance of such stability. Much of Devon s production in Canada is subject to government royalties that fluctuate with prices, which, therefore, will affect reported production. Estimates for Devon s future processing and transportation of oil, natural gas and NGL are based on the assumption that market demand and prices for oil, natural gas and NGL will be at levels that allow for profitable processing and transport of these products. As with our production estimates, there can be no assurance of such stability. The production, transportation, processing and marketing of oil, natural gas and NGL are complex processes which are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, tornadoes, extreme temperatures, and numerous other factors. Assumptions and Risks Related to Capital Expenditures Estimates: Devon s capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from Devon s price expectations for its future production, some projects may be accelerated, deferred or eliminated and, consequently, may increase or decrease capital expenditures. In addition, if the actual material or labor costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from Devon s estimates. Assumptions and Risks Related to Marketing and Midstream Estimates: Devon cautions that its future marketing and midstream revenues and expenses are subject to all of the risks and uncertainties normally incident to the marketing and midstream business. These risks include, but are not limited to, price volatility, environmental risks, mechanical failures, regulatory changes, the uncertainty inherent in estimating future processing volumes and pipeline throughput, cost of goods and services and other risks. Q OPERATIONS REPORT 20