Delaware Basin Production Expected to More than Double in 2017
Energen’s $790 MM Capital Program Includes Drilling 96 Gross Wells
FINANCIAL AND OPERATING HIGHLIGHTS
CY16
CY17 PLANS
WELL RESULTS
NOTE: 4Q16 supplemental slides available at www.energen.com
BIRMINGHAM, Ala.–(BUSINESS WIRE)–For the 3 months ended December 31, 2016, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $(54.5) million, or $(0.56) per diluted share. Excluding mark-to-market derivatives losses and a loss associated with prior-period property sales, Energen’s adjusted loss in 4Q16 totaled $(26.6) million, or $(0.27) per diluted share. This compares with adjusted income in 4Q15 of $28.4 million, or $0.36 per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.]
Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
[See “Non-GAAP Financial Measures” beginning on pp 12 for more information]
| 4Q16 | 4Q15 | ||||||||||||||||||||
| $M | $/dil. sh. | $M | $/dil. sh. | ||||||||||||||||||
| Net Income/(Loss) All Operations (GAAP) | $ | (54,470 | ) | $ | (0.56 | ) | $ | (590,806 | ) | $ | (7.50 | ) | |||||||||
| Less: Non-cash mark-to-market gains/(losses) | (22,792 | ) | (0.23 | ) | (66,984 | ) | (0.85 | ) | |||||||||||||
| Less: Asset impairments | (25 | ) | nm | (413,300 | ) | (5.25 | ) | ||||||||||||||
| Less: Pension and other expenses | — | — | (16,884 | ) | (0.21 | ) | |||||||||||||||
| Less: Income/(loss) associated with asset sales | (5,014 | ) | (0.05 | ) | (122,074 | ) | (1.55 | ) | |||||||||||||
| Adj. Income Continuing Operations (Non-GAAP) | $ | (26,639 | ) | $ | (0.27 | ) | $ | 28,436 | $ | 0.36 | |||||||||||
Note: Per share amounts may not sum due to rounding
Energen’s adjusted 4Q16 per-share loss approximated internal expectations despite a couple of unbudgeted, non-cash items that were largely offset by lower lease operating, marketing and transportation expenses (LOE), lower ad valorem and production taxes, and lower net salaries and general and administrative expenses (net SG&A). The unbudgeted items were a state deferred tax valuation allowance of $(3.6) million, or $(0.04) per diluted share and a depreciation, depletion and amortization (DD&A) look-back adjustment of $(2.6) million, or $(0.03) per diluted share.
Per-unit LOE was approximately 16 percent better-than-expected and benefited largely from lower expenses for workovers, non-operated activities, and water disposal; net SG&A expenses were lower by approximately 10 percent on a per-unit basis due to a variety of cost reductions, including professional services and non-cash compensation.
Production in 4Q16 totaled 53.5 thousand barrels of oil equivalents per day (mboepd) and exceeded the production guidance midpoint of 52.2 mboepd by 2.5 percent. Oil production was less than expected for a combination of reasons including lower Central Basin Platform oil production resulting, in part, from weather-related compressor downtime; the timing of non-operated production in the Delaware Basin; and the timing of pump failures in the northern Midland Basin.
Energen’s adjusted EBITDAX totaled $82.1 million in the 4th quarter of 2016 and exceeded internal expectations by approximately 10 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $201.2 million. [See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.]
Comments from the Chairman
“The year 2016 likely will be remembered by our industry as the year that the oil commodity price cycle bottomed out in the mid-$20s in February,” said James McManus, Energen’s chairman and chief executive officer. “I will remember it more for the determination and resiliency of our company. We were tested and challenged and came out stronger than ever.
“Today, with almost $400 million of cash and nothing drawn on our line of credit, our balance sheet is one of the very best among Permian drillers. We have gained a lot of efficiencies in our drilling and completion activities, and our per-unit operating costs continue to decline. As a result and in combination with high-quality rock, our outstanding assets in the Permian Basin generate excellent rates of return even at a $45 flat oil price.
“Beginning in 2017, we will move at an active pace to bring to production a sizeable inventory of uncompleted wells and, more importantly, resume a more typical drilling-and-completion cadence. At the same time, we will pursue improved well performance from more intensive frac designs and continue our work toward identifying the best spacing and completion designs needed for optimal well performance from multiple formations.
“Even as we anticipate attractive, 20 percent production growth in 2017, early results from stand-alone wells in the Midland and Delaware basins that were completed with our Generation 3 frac designs suggest the potential for even better growth in 2017 and beyond.”
2017 Capital and Operating Overview
Energen’s Board of Directors has approved a 2017 capital budget (excluding lease renewals and acquisitions) of $790 million. Approximately 84 percent of the capital is for drilling and completion activities, with approximately 14 percent for saltwater disposal wells and other facilities and 2 percent for non-operated and other activities.
The company’s capital budget supports completion of 124 gross/113 net wells, including 120 gross/110 net horizontal wells. All horizontal wells are scheduled to be completed with a Generation 3 frac design; this includes 61 gross/60 net wells drilled but not completed (DUC) at year-end 2016. In addition, 59 gross/50 net horizontal wells are scheduled to be drilled and completed in 2017 with the company’s 6- to 7-rig drilling program. Another 30 gross/27 net horizontal wells are set to be drilled and awaiting completion at year end. Energen also plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them. (Energen counts as completed those wells that have begun flow back).
Energen’s budget reflects a 15 percent increase in pressure pumping costs. Energen plans to use 6-7 frac crews through the first 9 months of 2017 and 2-5 in the 4th quarter.
Horizontal well targets include the Jo Mill, Middle Spraberry, Lower Spraberry and Wolfcamp A and B zones in the northern Midland Basin (Martin and Midland counties), Wolfcamp A and B in the central Midland Basin (Glasscock County) and Wolfcamp A and B in the core Delaware Basin (Reeves and Loving counties).
Taking into account Generation 3 frac designs and increased pressure pumping costs, the company’s estimated costs to drill, complete and equip 10,000’ lateral Wolfcamp A/B wells in the Delaware Basin and 10,000’ laterals in the Midland Basin in 2017 are approximately $7.9 million and $7.2 million, respectively.
| 2017 Horizontal Program | Gross/Net Wells | Avg. Lateral Length | Average WI | |||||||||
| Midland Basin | ||||||||||||
| YE16 DUC Completions | 44/43 | 9,600’ | 98% | |||||||||
| New Drills | 56/48 | 8,200’ | 85% | |||||||||
| New Drill Completions | 34/28 | |||||||||||
| YE17 DUCs | 22/20 | |||||||||||
| Delaware Basin | ||||||||||||
| YE16 DUCS | 17/17 | 8,765’ | 98% | |||||||||
| New Drills | 33/29 | 8,400’ | 89% | |||||||||
| New Drill Completions | 25/22 | |||||||||||
| YE17 DUCs | 8/7 |
Note: In addition to the above, Energen plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them.
| Capital Summary by Basin | 2017e Capital ($MM) | ||||
| Midland Basin | $ | 440 | |||
| Delaware Basin | $ | 345 | |||
| Central Basin and ARO | $ | 5 | |||
| Drilling & Development Capital | $ | 790 | |||
| Acquisitions/Unproved Leasehold | $ | 50 | |||
| Total Capital Expenditures | $ | 840 | |||
Acquisitions/Unproved Leasehold
In the first quarter of 2017, Energen acquired 1,400 net acres, primarily in the Delaware Basin, for $32 million; the company also purchased 640 net mineral acres in the Delaware Basin for approximately $18 million. The company does not budget for acquisitions. As Energen continues to pursue bolt-on acreage in its Permian footprint, investment in acquisitions is expected to increase.
2017 Production
Annual estimated 2017 production of 65.7 mboepd reflects a 20 percent year-over-year increase based on older generation frac designs. All 2017 completions will use Generation 3 frac designs (affecting approximately 8.9 mmboe, or 24.4 mboepd); if production response to Generation 3 frac designs is positive ̶ as early results from stand-alone wells in the northern Midland Basin and Delaware Basin suggest ̶ production growth could be higher.
In the Delaware Basin, where Energen’s activity level is significantly higher than in prior years, production is expected to more than double to 21.1 mboepd. In the Midland Basin, where activity is focused on density pattern drilling and completions, 2017 growth from horizontal wells is estimated to be 11 percent. Production growth in 2017 from all horizontal plays in the Permian Basin is estimated to be 37 percent.
Oil is expected to comprise 65 percent of the company’s total production mix in 2017, with natural gas liquids (NGL) and natural gas production estimated to make up 17 percent and 18 percent, respectively.
| Area | 2017 Guidance | 2016 Actual† | % Change | |||||||
| Midland Basin | 36.5 | 35.3 | 3.4 | |||||||
| Horizontal | 29.4 | 26.5 | 10.9 | |||||||
| Vertical | 7.1 | 8.8 | (19.3) | |||||||
| Delaware Basin | 21.1 | 10.3 | 104.9 | |||||||
| Central Basin Platform/Other | 8.1 | 9.0 | (10) | |||||||
| Total | 65.7 | 54.6 | 20.3 | |||||||
† Excludes asset sales
NOTE: Totals may not sum due to rounding
| Commodity | 2017 Guidance | 2016 Actual† | % Change | |||||||
| Oil | 42.8 | 34.5 | 24.1 | |||||||
| NGL | 11.1 | 9.4 | 18.1 | |||||||
| Gas | 11.8 | 10.7 | 10.3 | |||||||
| Total Production | 65.7 | 54.6 | 20.3 |
† Excludes asset sales
NOTE: Totals may not sum due to rounding
2017 Expenses
Energen expects most of its per-unit expenses to generally decline in 2017 as production increases. Per unit lease operating expenses (including marketing and transportation) are expected to be essentially flat, however, largely due to increased water handling as activity levels increase significantly in the Delaware Basin and as additional zones are completed in the northern Midland Basin. Also in the Midland Basin, the company plans to expand its use of electric submersible pumps, thereby increasing its electric power costs.
| Per BOE, except where noted | 2017e | CY16 Actual† | |||||
| LOE (production costs, marketing & transportation) | $7.60-$8.10 | $7.86 | |||||
| Production & ad valorem taxes (% of revenues, excluding hedges) | 6.6% | 6.6% | |||||
| DD&A expense | $17.60-$18.10 | $21.45 | |||||
| Salaries and general & administrative expense, net | $3.50-$3.90 |
$4.321 |
|||||
| Exploration expense (seismic, delay rentals, etc.) | $0.20-$0.40 | $0.27 | |||||
| Interest expense ($MM) | $30.0-$40.0 | $36.9 | |||||
| FF&E depreciation ($MM) | $4.4-$4.8 | $4.8 | |||||
| Accretion of discount on ARO ($MM) | $5.6-$6.0 | $6.2 | |||||
| Effective tax rate (%) | 35%-37% | 32% |
† Excludes asset sales
1 Excludes $0.44 per boe for RIF settlement and pension and pension settlement expenses
LOE per boe in CY17 is estimated to range from $6.15-$6.45 in the Midland Basin, $5.90-$6.20 in the Delaware Basin, and $19.70-$20.00 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.6 percent in the Midland Basin, 7.3 percent in the Central Basin Platform, and 6.2 percent in the Delaware Basin.
Net SG&A per boe in CY17 is estimated to be comprised of cash of $2.70-$2.90 per boe and non-cash, equity-based compensation of $0.80-$1.00 per boe.
Positive Response to First Generation 3 Completions in Midland Basin
Based on cumulative production through 90 days, Energen’s first two Midland Basin wells utilizing a Generation 3 frac design are responding very well. The average cumulative production of the two Wolfcamp B, stand-alone wells in Martin County is exceeding a 1 mmboe type curve for a 7,500- lateral by 30 percent.
The Tiger Unit SN 245-252 201H was drilled to a completed lateral length of 7,518’ and had a peak 24-hour IP rate of 1,791 boepd (91 percent oil) and a 30-day average peak rate of 1,439 (88 percent oil). The Tiger Unit SN 245-252 205H was drilled to a completed lateral length of 7,559’ and had a peak 24-hour IP rate of 1,436 boepd (88 percent oil) and a 30-day average peak rate of 1,167 (85 percent oil). These two wells were drilled on bolt-on acreage acquired in the second quarter of 2016.
Checkers Well Continues to Show Positive Response to Generation 3 Frac Design
Cumulative production from the Checkers St. 54-12-21 701H well in the Delaware Basin continues to outperform the 2.0 mmboe EUR type curve for a 10,000’ lateral length through 90 days. The Checkers St. well, disclosed last quarter, is producing from the Wolfcamp B interval in Reeves County and has a completed lateral length of 9,389’. Its previously disclosed peak 24-hour IP was 2,384 boepd (61% oil); its peak 30-day average rate was 2,072 boepd (58% oil).
The Checkers St. well was one of four wells drilled and completed in 2016 to hold core Delaware Basin acreage and is representative of the product mix the company expects to see across the bulk of its core acreage in Reeves, Loving, and western Ward counties.
YE16 Proved Reserves Total 316 MMBOE
Energen’s proved reserves at YE16 totaled 316.3 mmboe, down 11 percent from YE15 as reserve additions were more than offset by asset sales, lower commodity prices, and certain reserve reclassifications.
Horizontal drilling in the Midland and Delaware basins was the dominant driver of total proved reserve additions of 64.1 mmboe; these additions replaced 2016 production (excluding production from 2016 asset sales) by 320 percent. The company sold approximately 55 mmboe of proved reserves during 2016, primarily in the Delaware and San Juan basins. Negative revisions of 26 mmboe largely were due to lower SEC commodity prices and to reclassifying as “probable” certain wells that will no longer be developed in the five-year time horizon prescribed by the SEC (e.g., wells with short lateral lengths and others for which development has been delayed by a focus on other assets with higher returns).
Proved oil reserves represent approximately 63 percent of total proved reserves. Approximately 51 percent of Energen’s total proved reserves are proved developed.
Commodity prices used for calculating reserves at year-end 2016 were lower than those at year-end 2015. WTI oil prices declined 15 percent to $42.75 per barrel, while NGL prices (before transportation and fractionation) declined 5 percent to 39 cents per gallon and Henry Hub natural gas prices dropped 4 percent to $2.48 per thousand cubic feet (Mcf).
Proved Reserves by Basin (MMBOE)
| Basin | YE15 |
2016 |
2016 |
2016 |
2016 |
YE16 | |||||||||||||
| Midland Basin | 225.1 | (12.9) | (1.0) | 53.3 | (28.1) | 236.4 | |||||||||||||
| Delaware Basin | 69.7 | (4.3) | (38.1) | 10.8 | 0.9 | 39.0 | |||||||||||||
| Central Basin Platform/Other | 43.0 | (3.3) | — | — | 1.2 | 40.9 | |||||||||||||
| San Juan Basin | 16.9 | (1.1) | (15.8) | — | — | — | |||||||||||||
| TOTAL | 354.7 | (21.6) | (54.9) | 64.1 | (26.0) | 316.3 |
NOTE: Totals may not sum due to rounding
Proved Reserves by Commodity (MMBOE)
| Commodity | 2016 | 2015 | |||||
| Oil | 200 | 211 | |||||
| Natural gas liquids | 58 | 72 | |||||
| Natural gas | 58 | 72 | |||||
| TOTAL | 316 | 355 | |||||
NOTE: Totals may not sum due to rounding
YE16 3P Reserves & Contingent Resources (MMBOE)
| Basin | Proved | Probable | Possible | Contingent
Resources |
Total | |||||||||||
| Midland Basin | 236 | 142 | 150 | 881 | 1,410 | |||||||||||
| Delaware Basin | 39 | 9 | 21 | 764 | 833 | |||||||||||
| Central Basin Platform/Other | 41 | — | — | 2 | 42 | |||||||||||
| TOTAL | 316 | 151 | 171 | 1,647 | 2,285 | |||||||||||
NOTE: Totals may not sum due to rounding
The definitions of probable and possible reserves imply different probabilities of potential recovery in each classification; the quantities reported here are unrisked and based on the company’s estimate of current costs to drill wells in each basin/area and bring associated production to market. [See Cautionary Statements on p. 11].
Potential Drilling Inventory Totals 3,545 Net Horizontal Locations at YE16
Energen’s updated, unrisked potential drilling inventory of horizontal locations in the Wolfcamp, Cline, and Spraberry trends in the Permian Basin at year-end 2016 totaled 3,545. Of that amount, 2,594 net locations are in the Midland Basin, and 951 net locations are in the Delaware Basin. The company estimates that the associated net undeveloped resource potential is more than 2 billion BOE.
Potential drilling locations are engineered based on the company’s existing acreage and spacing plans and may change over time as the company and offset operators drill wells in each target zone.
4th Quarter 2016 Results
Production (excludes asset sales) (mboepd)
| Commodity | 4Q16 | 4Q16 Guidance Mdpt | 4Q15 | 3Q16 | 2Q16 | 1Q16 | |||||||||||||
| Oil | 32.0 | 33.4 | 36.2 | 35.8 | 36.5 | 33.6 | |||||||||||||
| NGL | 9.7 | 9.1 | 9.6 | 10.4 | 9.4 | 8.3 | |||||||||||||
| Natural Gas | 11.8 | 9.7 | 11.0 | 10.3 | 10.2 | 10.4 | |||||||||||||
| Total | 53.5 | 52.2 | 56.8 | 56.6 | 56.0 | 52.3 | |||||||||||||
| Area | 4Q16 | 4Q16 Guidance Mdpt | 4Q15 | 3Q16 | 2Q16 | 1Q16 | ||||||||||||||
| Midland Basin | 33.2 | 32.9 | 35.9 | 38.2 | 37.1 | 33.0 | ||||||||||||||
| Horizontal | 25.0 | 24.8 | 25.5 | 29.2 | 28.5 | 23.3 | ||||||||||||||
| Vertical | 8.2 | 8.1 | 10.4 | 9.0 | 8.6 | 9.7 | ||||||||||||||
| Delaware Basin | 11.3 | 10.4 | 11.6 | 9.6 | 9.8 | 10.3 | ||||||||||||||
| Central Basin/Other | 9.0 | 8.9 | 9.3 | 8.7 | 9.1 | 9.0 | ||||||||||||||
| Total | 53.5 | 52.2 | 56.8 | 56.6 | 56.0 | 52.3 |
Note: Totals in production tables above may not sum due to rounding.
Average Realized Sales Prices (excludes asset sales)
| Commodity | 4Q16 | 4Q15 | % Change | |||||||||
| Oil (per barrel) | $ | 41.36 | $ | 74.09 | (44) | |||||||
| NGL (per gallon) | $ | 0.38 | $ | 0.28 | 36 | |||||||
| Natural Gas (per Mcf) | $ | 2.16 | $ | 4.08 | (47) | |||||||
Average Prices Before Effects of Hedges (excludes asset sales)
| Commodity | 4Q16 | 4Q15 | % Change | |||||||||
| Oil (per barrel) | $ | 45.57 | $ | 39.40 | 16 | |||||||
| NGL (per gallon) | $ | 0.38 | $ | 0.28 | 36 | |||||||
| Natural Gas (per Mcf) | $ | 2.27 | $ | 1.84 | 23 | |||||||
Expenses (excludes asset sales)
| Per BOE, except where noted | 4Q16 | 4Q15 | |||||||
| LOE (including marketing and transportation) | $ | 7.85 | $ | 8.52 | |||||
| Production & ad valorem taxes | $ | 1.89 | $ | 1.90 | |||||
| DD&A | $ | 20.79 | $ | 27.46 | |||||
| Net SG&A† | $ | 4.25 | $ | 5.11 | |||||
| Interest ($MM) | $ | 9.0 | $ | 10.0 | |||||
† Excludes $5.02 per BOE in 4Q15 for pension and pension settlement expenses.
2016 Capital Summary
| 2016 Capital
($MM) |
Wells Drilled | Wells Completed | ||||||||||
| Operated Gross (Net) | Operated Gross (Net) | |||||||||||
| Midland Basin | $ | 307 | 52 (50) * | 56 (55) † | ||||||||
| Delaware Basin | $ | 118 | 21 (21) ** |
4 (4) |
||||||||
| Central Basin/Other/ARO | $ | 8 | ||||||||||
| Drilling & Development Capital |
$ |
433 |
1 |
73 (71) |
60 (59) |
|||||||
| Acquisitions/Unproved Leasehold | $ | 148 | ||||||||||
| Total Capital Expenditures | $ | 581 | ||||||||||
1 Includes approximately $28 mm for facilities in the Midland Basin, $19 mm for facilities in the Delaware Basin and $6 mm for non-operated activities and miscellaneous items
* Includes 6 gross (6 net) vertical wells to hold acreage and 3 gross (2 net) horizontal wells to hold new leasehold, 1 gross (1 net) well to complete a pad, 2 gross (2 net) wells to hold acreage, and 40 gross (39 net) new DUC drills in 2H16
** Includes 4 gross (4 net) horizontal wells to hold acreage and 17 gross and net new DUC drills in 2H16
† Includes 6 gross (6 net) vertical wells, 3 gross (2 net) horizontal wells to hold new leasehold, 47 gross(47 net) development program completions in 1H16
In addition to drilling and development, Energen acquired approximately 9,000 net acres in its focus areas in the Delaware and Midland basins in 2016 for approximately $120 million; this includes approximately 1,100 net acres acquired in 4Q16. During 2016, Energen also invested approximately $11 million to acquire mineral acreage and approximately $17 million for lease renewals and miscellaneous items.
Liquidity Update
As of December 31, 2016, Energen had cash of $386.1 million and debt of $551.4 million; the company had nothing drawn on its $1.05 billion line of credit. Energen’s total net debt-to-2016 adjusted EBITDAX was 0.6x.
CY17 Quarterly Guidance
Production
| Guidance by Basin (mboepd) | 1Q17 | 2Q17 | 3Q17 | 4Q17 | |||||||||
| Midland Basin | 30.6 | 34.2 | 38.6 | 42.3 | |||||||||
| Delaware Basin | 11.3 | 19.8 | 24.6 | 28.4 | |||||||||
| Central Basin Platform/Other | 8.3 | 8.2 | 8.1 | 7.9 | |||||||||
| Total | 50.2 | 62.2 | 71.3 | 78.6 |
| Guidance by Commodity (mboepd) | 1Q17 | 2Q17 | 3Q17 | 4Q17 | |||||||||
| Oil | 31.4 | 40.6 | 46.6 | 52.1 | |||||||||
| NGL | 9.1 | 10.5 | 11.9 | 12.8 | |||||||||
| Gas | 9.7 | 11.1 | 12.8 | 13.7 | |||||||||
| Total | 50.2 | 62.2 | 71.3 | 78.6 | |||||||||
Operating Expenses
| Per BOE, except where noted | 1Q17 | 2Q17 | 3Q17 | 4Q17 | |||||||||
| LOE* | $9.10-$9.40 | $8.10-$8.40 | $7.35-$7.65 | $6.90-$7.20 | |||||||||
| Production & ad valorem taxes** | 7.5% | 6.6% | 6.3% | 6.3% | |||||||||
| DD&A expense | $20.75-$21.15 | $18.50-$18.90 | $17.20-$17.60 | $15.50-$15.9† | |||||||||
| SG&A, net | $4.95-$5.25 | $3.85-$4.15 | $3.05-$3.35 | $2.75-$3.05 | |||||||||
| Exploration exp. (seismic, delay rentals, etc.) | $0.30-$0.40 | $0.20-$0.30 | $0.30-$0.40 | $0.25-$0.35 | |||||||||
| Effective tax rate (%) | 33%-35% | 37%-39% | 36%-38% | 34%-36% |
* Production costs, marketing & transportation
** % of revenues, excluding hedges
† Does not include estimate of 4Q17 DD&A look-back adjustment
| Gross Horizontal Wells | 1Q17 | 2Q17 | 3Q17 | 4Q17 | ||||||||||
| Midland Basin | ||||||||||||||
| Wells Drilled | 17 | 13 | 12 | 14 | ||||||||||
| First Production | 10 | 26 | 18 | 24 | ||||||||||
| Delaware Basin | ||||||||||||||
| Wells Drilled | 13 | 4 | 8 | 8 | ||||||||||
| First Production | 3 | 14 | 11 | 8 | ||||||||||
Hedge Position for 2017
Energen has increased its 2017 hedge positions for oil, NGL, and natural gas and has initiated hedging for 2018. Hedges are in place for 70 percent of the company’s 2017 estimated oil production, 47 percent of its estimated NGL production, and 60 percent of its natural gas production. Energen also has hedged the Midland to Cushing differential on 9.1 million barrels (approximately 69 percent) of its sweet oil production in 2017 at an average price of $(0.63).
Energen’s total oil hedge position for 2017 is as follows:
| Oil | 2017 Hedge Volumes | Avg. NYMEX Price | ||||||
| Swaps | 6.1 mmbo | $ 49.77 per barrel | ||||||
|
Three way Collars1 |
4.8 mmbo | |||||||
| Call Price | $ 62.18 per barrel | |||||||
| Put Price | $ 45.00 per barrel | |||||||
| Short Put Price | $ 35.00 per barrel |
Contacts
Energen Corporation
Julie S. Ryland, 205-326-8421