Exhibit 99.1
ENERGEN CORPORATION
605 Richard Arrington Jr. Blvd. N.
Birmingham, AL 35203-2707
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For Release: 4:15 p.m. ET | | Contacts: | | Julie S. Ryland |
Thursday, May 4, 2017 | | | | 205.326.8421 |
NEW ENERGEN WELLSWITH GENERATION 3FRACS SIGNIFICANTLY OUTPERFORMING
New Gen 3 Wells Drive 5% Production Beat in 1Q17; Oil Production Outpaces Guidance by 6%
Energen Adds >6,900 Net Lease Acres to Permian Basin Footprint through YTDBolt-On Acquisitions
FINANCIAL AND OPERATING HIGHLIGHTS
1Q17
| • | | Driven by performance of new wells with Generation 3 fracs, 1Q17 production increases 5% to 52.8 mboepd |
| • | | 1Q17 oil production outpaces guidance by 6% |
| • | | Delaware Basin production exceeds guidance by 13% |
| • | | Per-unit net SG&A outperformed midpoint of guidance range by 16% |
| • | | 1Q17 adjusted EBITDAX exceeds internal expectations by 15% |
| • | | Latestbolt-on acquisitions bring total for first four months of 2017 to 6,923 net lease acres for≈$147 mm |
WELL RESULTS
| • | | Average cumulative production of wells completed with Generation 3 fracs outperforming across the board |
| • | | 5 new Wolfcamp A/B wells in Glasscock County with 75 days of production history completed in 1Q17 |
| | • | | Average cumulative production≈15% above thehigh-end, 1.3 MMBOE EUR type curve for a 10,000’ lateral (77% oil) |
| | • | | Average24-hour IP of 1,684 boepd (74% oil) and peak30-day average of 1,465 boepd (74% oil); average completed lateral length 9,541’ |
| • | | 2 new Wolfcamp A/B wells with 80 days of production history completed in Delaware Basin in 1Q17 |
| | • | | Average cumulative production≈80% above thehigh-end, 2.0 MMBOE EUR type curve for a 10,000’ lateral (61% oil) |
| | • | | Average24-hour IP of 2,033 boepd (62% oil) and peak30-day average of 1,825 boepd (60% oil); average completed lateral length 4,654’ |
CY17 UPDATE
| • | | $60-$65 mm increase in CY17 estimated drilling and development capital associated with additional operated completions andnon-op new drills, increased operated working interests and facilities |
| • | | Operated horizontal projects in 2017 include drilling 77 net wells, completing 115 net wells (including 60 net DUCs), and ending the year with 22 net DUCs |
| • | | Non-operated projects include additional 12 gross (2.8 net) wells for total of 26 gross (4 net) wells |
NOTE: 1Q17 supplemental slides available at www.energen.com
BIRMINGHAM, Alabama– For the 3 months ended March 31, 2017, Energen Corporation (NYSE: EGN) reported GAAP net income from all operations of $33.4 million, or $0.34 per diluted share. Adjusting for anon-cash gain onmark-to-market derivatives and a smallnon-cash impairment loss, Energen had an adjusted loss in 1Q17 of $(12.4 million), or $(0.13) per diluted share. This compares with an adjusted loss in 1Q16 of $(53.6 million), or $(0.62) per diluted share.[See“Non-GAAP Financial Measures” beginning on pp 10 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 10 for more information]
| | | | | | | | | | | | | | | | |
| | | 1Q17 | | | 1Q16 | |
| | | $M | | | $/dil. sh. | | | $M | | | $/dil. sh. | |
Net Income/(Loss) All Operations (GAAP) | | $ | 33,403 | | | $ | 0.34 | | | $ | (203,116 | ) | | $ | (2.34 | ) |
Less:Non-cashmark-to-market gains/(losses) | | | 46,692 | | | | 0.48 | | | | (166 | ) | | | nm | |
Less: Asset impairments | | | (939 | ) | | | (0.01 | ) | | | (121,420 | ) | | | (1.40 | ) |
Less: Pension settlement and other expenses | | | — | | | | — | | | | (4,801 | ) | | | (0.06 | ) |
Less: Income/(loss) associated with asset sales | | | — | | | | — | | | | (23,132 | ) | | | (0.27 | ) |
Adj. Income Continuing Operations(Non-GAAP) | | $ | (12,350 | ) | | $ | (0.13 | ) | | $ | (53,597 | ) | | $ | (0.62 | ) |
Note: Per share amounts may not sum due to rounding
Energen’s adjusted 1Q17per-share loss was less than internal expectations by $3.8 million, or $0.04 per diluted share, largely due to above-budget production and lower-than-expected net salaries and general and administrative expense (SG&A), partially offset by increased depreciation, depletion, and amortization expense (DD&A) largely due to increased volumes and to the timing of exploration expense.
Production in 1Q17 totaled 52.8 thousand barrels of oil equivalents per day (mboepd) and exceeded guidance of 50.2 mboepd by 5.2 percent mainly due to the impact of new wells completed with Generation 3 fracs. Total oil production was up 6 percent over guidance largely due to stronger-than-expected oil volumes in the Delaware Basin. Net SG&A expenses were lower due to a variety of cost reductions, includingnon-cash compensation and legal services.
Energen’s adjusted EBITDAX totaled $95.6 million in the 1st quarter of 2017 and exceeded internal expectations by approximately 15 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $44.0 million.[See“Non-GAAP Financial Measures” beginning on pp 10 for more information and reconciliation.]
Comments from the Chairman
“We are very encouraged by the performance of the wells we have completed with our Generation 3 frac design,” said James McManus, Energen’s chairman and chief executive officer. “For those Gen 3 wells with at least 75 days of production history, cumulative production by formation is outperforming the type curves associated with the highest potential EURs we have identified.
“Since our ranges of EUR outcomes are based on the performance ofpre-Gen 3 wells, one of our major goals for Gen 3 fracs is to achieve well results that meet or surpass the high end of these ranges. We are very excited to see that early results are doing just that.”
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1st Quarter 2017 Results
Production (excludes asset sales) (mboepd)
| | | | | | | | | | | | | | | | |
Commodity | | 1Q17 | | | 1Q16 | |
| | Actual | | | Guidance | | | % Change | | |
Oil | | | 33.3 | | | | 31.4 | | | | 6 | | | | 33.6 | |
NGL | | | 8.9 | | | | 9.1 | | | | (2 | ) | | | 8.3 | |
Natural Gas | | | 10.6 | | | | 9.7 | | | | 10 | | | | 10.4 | |
| | | | | | | | | | | | | | | | |
Total | | | 52.8 | | | | 50.2 | | | | 5 | | | | 52.3 | |
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Area | | 1Q17 | | | 1Q16 | |
| | Actual | | | Guidance | | | % Change | | |
Midland Basin | | | 31.8 | | | | 30.6 | | | | 4 | | | | 33.0 | |
Delaware Basin | | | 12.8 | | | | 11.3 | | | | 13 | | | | 10.3 | |
Central Basin/Other | | | 8.3 | | | | 8.3 | | | | — | | | | 9.0 | |
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Total | | | 52.8 | | | | 50.2 | | | | 5 | | | | 52.3 | |
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Note: Totals in production tables above may not sum due to rounding.
Average Realized Sales Prices (excludes asset sales)
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Commodity | | 1Q17 | | | 1Q16 | | | % Change | |
Oil (per barrel) | | $ | 46.95 | | | $ | 32.34 | | | | 45 | |
NGL (per gallon) | | $ | 0.42 | | | $ | 0.22 | | | | 91 | |
Natural Gas (per mcf) | | $ | 2.39 | | | $ | 1.66 | | | | 44 | |
Average Prices before Effects of Hedges (excludes asset sales)
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Commodity | | 1Q17 | | | 1Q16 | | | % Change | |
Oil (per barrel) | | $ | 48.96 | | | $ | 30.67 | | | | 60 | |
NGL (per gallon) | | $ | 0.46 | | | $ | 0.22 | | | | 109 | |
Natural Gas (per mcf) | | $ | 2.46 | | | $ | 1.55 | | | | 59 | |
Expenses (excludes asset sales)
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Per BOE, except where noted | | 1Q17 | | | 1Q16 | |
| | Actual | | | Guidance | | |
LOE* | | $ | 8.68 | | | $ | 9.25 | | | $ | 8.43 | |
Production & ad valorem taxes** | | | 7.3 | % | | | 7.5 | % | | | 8.8 | % |
DD&A | | $ | 20.71 | | | $ | 20.95 | | | $ | 23.15 | |
Net SG&A† | | $ | 4.29 | | | $ | 5.10 | | | $ | 4.52 | |
Exploration†† | | $ | 0.76 | | | $ | 0.35 | | | $ | 0.03 | |
Interest ($mm) | | $ | 9.0 | | | $ | 8.9 | | | $ | 9.8 | |
| * | Production costs, marketing & transportation |
| ** | % of revenues, excluding hedges |
| † | Excludes $1.56 per BOE in 1Q16 for pension settlement and other expenses |
| †† | Includes seismic, delay rentals, etc. |
Operations Update
During the first quarter, Energen turned to production 10 gross (9 net) wells drilled in Glasscock County in the central Midland Basin and 2 gross (2 net) wells in the Delaware Basin. All 12 of these wells were part of Energen’s DUC inventory at YE16. The company set casing on 19 gross (17 net) wells in the first quarter. The company operated an average of 6.5 horizontal drilling rigs in the first quarter and an average of 6 frac crews.
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Drilling efficiencies continued in the first quarter, with two new “internal best times” for days to drill from spud to total depth. In only 15 days, Energen drilled a9,856-foot lateral Wolfcamp B well in the northern Midland Basin; and in just under 15 days, the company drilled a10,733-foot lateral Middle Spraberry well.
Positive Response to Early Generation 3 Completions
For those Gen 3 wells with at least 75 days of production history, the average cumulative production by formation outperformed the type curves associated with the highest potential EURs identified by the company. Because the ranges of EURs are based on the performance ofpre-Gen 3 wells, the company hopes to achieve Gen 3 well results that meet or surpass the high end of these ranges.
Energen’s first two Midland Basin wells utilizing a Generation 3 frac design (the “Tiger Unit” wells) — continued to respond very well. The average cumulative production of the two Wolfcamp B, stand-alone wells in Martin County exceeded the 1 mmboe type curve for a7,500-lateral by an average of approximately 20 percent through 165 days. Oil comprised 82 percent of the product mix.
At 75 days of production, five new Glasscock County completions were approximately 15 percent above the 1.3 mmboe EUR type curve for a 10,000’ lateral. Oil comprised 77 percent of the product mix. The company considers this a particularly attractive result since four of the wells are producing from the Wolfcamp B; the fifth well is producing from the Wolfcamp A. The five wells had an average24-hour IP of 1,684 boepd (74% oil) and peak30-day average of 1,465 boepd (74% oil); their average completed lateral length was 9,541’.
Cumulative production from the Checkers St.54-12-21 701H well in the Delaware Basin continued to outperform the 2.0 mmboe EUR type curve for a 10,000’ lateral length by 6 percent through 195 days. The Checkers St. well is producing from the Wolfcamp B interval in Reeves County. Oil comprised 55 percent of the product mix.
The two Delaware Basin wells placed on production in the first quarter were 4,600 foot laterals; normalized to 10,000 feet, these two wells averaged 80 percent above the 2.0 mmboe EUR type curve for a 10,000’ lateral through 80 days. Oil comprised 61 percent of the product mix. The two Delaware Basin wells had an average24-hour IP of 2,033 boepd (62% oil) and peak30-day average of 1,825 boepd (60% oil); their average completed lateral length was 4,654’.
2017 Capital and Operating Overview
Energen estimates that it will invest an additional$60-$65 million in 2017 for 4 more gross completions and to participate in an additional 2.8 netnon-operated wells, for increased working interests, and for facilities. Since the end of 1Q17, Energen has seen rising pressure on the costs of a wide variety of completion services; withoutoff-setting efficiencies or other savings, the company estimates that it could see capital spending for drilling and development increase another$45-$50 million.
The company’s revised capital budget of$850-$900 million for drilling and development activities supports completion of 128 gross/118 net operated wells, including 124 gross/115 net horizontal wells. All horizontal wells are scheduled to be completed with a Generation 3 frac design.
Horizontal completions include 61 gross/60 net wells drilled but not completed (DUC) atyear-end 2016 and 63 gross/55 net horizontal wells that are scheduled to be drilled and completed in 2017 with the company’s6- to7-rig drilling program. Another 24 gross/22 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.
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Energen’snon-operated opportunities have increased, and the company has agreed to participate in a total of 4 net wells. Such opportunities are difficult to predict and, therefore, are not budgeted until the company has visibility on an operator’s plans.
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2017 Operated Horizontal Program | | Gross/Net Wells | | | Avg. Lateral | | | Average WI | |
Midland Basin | | | | | | | | | | | | |
YE16 DUC Completions | | | 44/43 | | | | 9,600’ | | | | 98 | % |
New Drills | | | 54/46 | | | | 8,330’ | | | | 84 | % |
New Drill Completions | | | 39/32 | | | | | | | | | |
YE17 DUCs | | | 15/14 | | | | | | | | | |
Delaware Basin | | | | | | | | | | | | |
YE16 DUC Completions | | | 17/17 | | | | 8,765’ | | | | 98 | % |
New Drills | | | 33/31 | | | | 8,410’ | | | | 95 | % |
New Drill Completions | | | 24/23 | | | | | | | | | |
YE17 DUCs | | | 9/8 | | | | | | | | | |
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.
Acquisitions/Unproved Leasehold
In the first four months of 2017, Energen acquired a total of 6,923 net lease acres, primarily in the Delaware Basin, for approximately $147 million; the company also has purchased 690 net mineral acres in the Delaware Basin for approximately $20 million. The company does not budget for acquisitions.
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Capital Summary by Basin | | 2017e Capital ($MM) | |
Midland Basin | | $ | 470 - 500 | |
Delaware Basin | | $ | 375 - 395 | |
Central Basin, ARO, Other | | $ | 5 | |
Drilling & Development Capital | | $ | 850 - 900 | |
Acquisitions/Unproved Leasehold | | $ | 167 | |
| | | | |
Total Capital Expenditures | | $ | 1,017 - 1,067 | |
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Liquidity Update
As of March 31, 2017, Energen had cash of $88.7 million and debt of $544.6 million; the company had nothing drawn on its $1.05 billion line of credit, and its borrowing base currently is $1.4 billion. Energen estimates that its total netdebt-to-2017 adjusted EBITDAX will range from 1.2x - 1.3x.
CY17 Guidance
Production (mboepd)
| | | | | | | | | | | | | | | | | | | | |
Guidance by Basin | | 1Q17a | | | 2Q17e | | | 3Q17e | | | 4Q17e | | | CY17e | |
Midland Basin | | | 31.8 | | | | 34.2 | | | | 38.6 | | | | 42.3 | | | | 36.8 | |
Delaware Basin | | | 12.8 | | | | 19.8 | | | | 24.6 | | | | 28.4 | | | | 21.4 | |
Central Basin Platform/Other | | | 8.3 | | | | 8.2 | | | | 8.1 | | | | 7.9 | | | | 8.1 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 52.8 | | | | 62.2 | | | | 71.3 | | | | 78.6 | | | | 66.3 | |
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| | | | | | | | | | | | | | | | | | | | |
Guidance by Commodity | | 1Q17a | | | 2Q17e | | | 3Q17e | | | 4Q17e | | | CY17e | |
Oil | | | 33.3 | | | | 40.6 | | | | 46.6 | | | | 52.1 | | | | 43.2 | |
NGL | | | 8.9 | | | | 10.5 | | | | 11.9 | | | | 12.8 | | | | 11.0 | |
Gas | | | 10.6 | | | | 11.1 | | | | 12.8 | | | | 13.7 | | | | 12.1 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 52.8 | | | | 62.2 | | | | 71.3 | | | | 78.6 | | | | 66.3 | |
| | | | | | | | | | | | | | | | | | | | |
Note: Totals in production tables above may not sum due to rounding.
Estimated 2017 production of 66.3 mboepd reflects a 1 percent increase over prior guidance as a result of 1Q17 actual results. Production guidance for the remainder of the year is unchanged and reflects estimated production with Generation 2 fracs. Given that all wells completed in 2017 will use the Generation 3 frac design, if the associated production response continues to be positive, year-over-year production growth could be higher than the current estimate of 21 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.
Operating Expenses
| | | | | | | | | | | | |
Per BOE, except where noted | | 1Q17a | | | 2Q17e | | 3Q17e | | 4Q17e | | CY17e |
LOE* | | $ | 8.68 | | | $8.10-$8.40 | | $7.35-$7.65 | | $6.90-$7.20 | | $7.60-$8.00 |
Production & ad valorem taxes** | | | 7.3 | % | | 6.9% | | 6.6% | | 6.5% | | 6.8% |
DD&A expense† | | $ | 20.71 | | | $17.95-$18.35 | | $17.20-$17.60 | | $15.50-$15.90 | | $17.50-$17.90 |
SG&A, net | | $ | 4.29 | | | $3.70-$4.00 | | $3.10-$3.40 | | $2.70-$3.00 | | $3.25-$3.65 |
Exploration†† | | $ | 0.76 | | | $0.20-$0.30 | | $0.30-$0.40 | | $0.05-$0.15 | | $0.30-$0.40 |
Interest ($mm) | | $ | 9.0 | | | $9.0-$9.4 | | $9.3-$9.7 | | $9.5-$9.9 | | $37.0-$38.0 |
Effective tax rate | | | 32 | % | | 37%-39% | | 36%-38% | | 35%-37% | | 36%-38% |
| * | Production costs, marketing & transportation |
| ** | % of revenues, excluding hedges |
| † | 4Q17 and CY17 does not include estimate of 4Q17 DD&A look-back adjustment |
| †† | Includes seismic, delay rentals, etc. |
LOE per boe in CY17 is estimated to range$5.65-$5.95 in the Delaware Basin,$6.25-$6.55 in the Midland Basin, and$19.50-$19.80 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.1 percent in the Delaware Basin, 6.9 percent in the Midland Basin, and 7.8 percent in the Central Basin Platform.
Net SG&A per boe in CY17 is estimated to be comprised of cash compensation of$2.60-$2.80 per boe andnon-cash, equity-based compensation of$0.65-$0.85 per boe.
Hedges
For the remaining 9 months of 2017, approximately 68 percent of the company’s estimated oil production of 12.8 MMBOE is hedged as well as 46 percent of its estimated NGL production and 59 percent of its natural gas production. Hedges also are in place that limit the company’s exposure to the Midland to Cushing oil differential. Energen has hedged the WTI Midland to WTI Cushing (sweet oil) differential for 7.6 million barrels at an average price of $(0.64) per barrel. Energen estimates that approximately 86 percent of its oil production for the remainder of the year will be sweet.
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Energen’s total oil hedge position for the remainder of 2017 is as follows:
| | | | | | | | |
Oil | | 2017 Hedge Volumes | | | Avg. NYMEX Price | |
Swaps | | | 5.0 mmbo | | | $ | 50.13 per barrel | |
Three way Collars¹ | | | 3.6 mmbo | | | | | |
Call Price | | | | | | $ | 62.18 per barrel | |
Put Price | | | | | | $ | 45.00 per barrel | |
Short Put Price | | | | | | $ | 35.00 per barrel | |
| ¹ | When the NYMEX price is above the call price, Energen receives the call price; when the NYMEX price is between the call price and the put price, Energen receives the NYMEX price; when the NYMEX price is between the put price and the short put price, Energen receives the put price; and when the NYMEX price is below the short put price, Energen receives the NYMEX price plus the difference between the put price and the short put price. |
Energen’s total natural gas and NGL hedge positions for the remainder of 2017 are as follows:
| | | | | | | | | | | | |
Commodity | | Hedge Volumes | | Production Guidance | | % Hedged | | | Avg. NYMEXe Price | |
NGL | | 62.4 mm gallons | | 135.6 mm gallons | | | 46 | % | | $ | 0.57 per gallon | |
Natural gas | | 12.3 bcf | | 20.7 bcf | | | 59 | % | | $ | 3.28 per Mcf | |
Note: Includes known actuals
2Q17 Hedges
Energen’s total oil hedge position for 2Q17 is as follows:
| | | | | | | | |
Oil | | 2Q17 Hedge Volumes | | | Avg. NYMEX Price | |
Swaps | | | 1.0 mmbo | | | $ | 47.97 per barrel | |
Three way Collars | | | 1.2 mmbo | | | | | |
Call Price | | | | | | $ | 62.18 per barrel | |
Put Price | | | | | | $ | 45.00 per barrel | |
Short Put Price | | | | | | $ | 35.00 per barrel | |
Energen’s total natural gas and NGL hedge positions for 2Q17 as follows:
| | | | | | | | | | | | |
Commodity | | Hedge Volumes | | Production Guidance | | Hedge % | | | NYMEXe Price | |
NGL | | 20.8 mm gallons | | 40.0 mm gallons | | | 52 | % | | $ | 0.57 per gallon | |
Natural Gas | | 3.6 bcf | | 6.1 bcf | | | 59 | % | | $ | 3.31 per mcf | |
Note: Includes known actuals
Energen also has hedged the Midland to Cushing differential on 2.0 million barrels (approximately 66 percent) of its estimated 2Q17 sweet oil production at an average price of $(0.58).
Basis Differentials and Sensitivities
The company’s average realized prices will reflect commodity and basis hedges; oil transportation charges of approximately $2.00 per barrel in the last nine months of CY17 ($2.03 per barrel in 2Q17), NGL transportation and fractionation fees of approximately $0.13 per gallon for the remainder of the year ($0.13 per gallon in 2Q17), and gas and oil basis differentials applicable to unhedged production. In addition, natural gas and NGL production is subject to a percent of proceeds contract of approximately 85%.
The assumed gas basis for all open contracts for the remainder of 2017 is $(0.40) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $(1.30) and $(1.85), respectively. Energen’s assumed commodity prices for unhedged production for the last nine months of 2017 are: $52.00 per barrel of oil, $0.60 per gallon of NGL, and $3.30 per Mcf of gas(May-December).
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Estimated Price Realizations(pre-hedge):
| | | | | | | | |
| | | 2Q17 | | | ROY 2017 | |
Crude oil (% of NYMEX/WTI) | | | 93 | | | | 93 | |
NGL (after T&F) (% of NYMEX/WTI) | | | 32 | | | | 33 | |
Natural gas (% of NYMEX/Henry Hub) | | | 74 | | | | 76 | |
2018 Hedges
Energen’s total oil hedge position for 2018 is as follows:
| | | | | | | | |
Oil | | 2018 Hedge Volumes | | | Avg. NYMEX Price | |
Three way Collars | | | 7.4 mmbo | | | | | |
Call Price | | | | | | $ | 63.85 per barrel | |
Put Price | | | | | | $ | 50.00 per barrel | |
Short Put Price | | | | | | $ | 40.00 per barrel | |
Energen’s total natural gas and NGL hedge positions for 2018 as follows:
| | | | | | |
Commodity | | Hedge Volumes | | NYMEXe Price | |
NGL | | 105.8 mm gallons | | $ | 0.59 per gallon | |
Natural Gas | | 3.6 bcf | | $ | 3.06 per mcf | |
Supplemental Slides and Conference Call
1Q17 supplemental slides associated with Energen’s quarterly release and conference call are available atwww.energen.com. Energen will hold its quarterly conference call Friday, May 5, at 11:00 a.m. EDT. Investment community members may participate by calling1-877-407-8289 (reference Energen earnings call). A live audio Webcast of the program as well as a replay may be accessed viawww.energen.com.
Energen Corporation is anoil-focused exploration and production company with operations in the Permian Basin in west Texas and New Mexico. For more information, go towww.energen.com.
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FORWARD LOOKING STATEMENTS: All statements, other than statements of historical fact, appearing in this release constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. Forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this news release. Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise. Additional information regarding ourforward-looking statements and related risks and uncertainties that could affect future results of Energen, can be found in the Company’s periodic reports filed with the Securities and Exchange Commission and available on the Company’s website -www.energen.com.
CAUTIONARY STATEMENTS: The SEC permits oil and gas companies to disclose in SEC filings 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. Outside of SEC filings, we use the terms “estimated ultimate recovery” or “EUR,” reserve or resource “potential,” “contingent resources” and other descriptions of volumes ofnon-proved reserves or resources potentially recoverable through additional drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. We have not risked EUR estimates, potential drilling locations, and resource potential estimates. Actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of ouron-going drilling program, which will be directly affected by the availability of capital, drilling, and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approvals, and geological and mechanical factors. Estimates of unproved reserves, type/decline curves,per-well EURs, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, initial production rates contained in this news release are subject to decline over time and should not be regarded as reflective of sustained production levels.
Financial, operating, and support data pertaining to all reporting periods included in this release are unaudited and subject to revision.
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