 | Exhibit 99.1
ENERGEN CORPORATION 605 Richard Arrington, Jr. Boulevard North Birmingham, Alabama 35203-2707 Telephone (205) 326-2700
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For Release: 4:30 p.m. ET Contacts: Julie S. Ryland Thursday, November 5, 2015 205.326.8421 | ||||
ENERGEN’S FIRST MIDDLE SPRABERRY WELLS GENERATE SOLID EARLY RATES 10,000’ Lateral Wells in Glasscock County Generate Excellent Results in Wolfcamp A, B and C 3Q15 Production Tops 64,000 BOEPD
Highlights
• Results of three 10,000’ laterals in Glasscock County underscore capital efficiency of longer lateral length wells.
• Two Middle Spraberry wells generate exciting early results in Martin County.
• Latest Lower Spraberry result in Martin County, together with continued performance of Lower Spraberry wells drilled earlier this year, support the play’s attractive return potential.
• Development drilling program begins in Martin County; 27 Lower Spraberry, Wolfcamp A and Wolfcamp B wells drilled with 10 more to be drilled in 4th quarter.
• 3Q15 production totaled 64,054 boepd, exceeding guidance midpoint by 2%.
• 3Q15 oil production grew 20% from same period last year.
• CY15 production guidance midpoint reaffirmed at 22.7 MMBOE (62,252 boepd).
• Drilling continues in New Mexico to assess Mancos oil potential on company’s San Juan Basin acreage.
• D&C costs of 7,500’ lateral Wolfcamp A in Glasscock County trending down to $5.6 million.
BIRMINGHAM, Alabama – For the 3 months ended September 30, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $227.9 million, or $(2.89) per diluted share. Excluding mark-to-market derivatives losses, commodity price-related impairments primarily of proved properties in the Central Basin Platform, and other items, Energen’s adjusted income in the 3rd quarter of 2015 totaled $28.6 million, or $0.36 per diluted share. This compares with adjusted income from continuing operations in the 3rd quarter of 2014 of $38.9 million, or $0.53 per diluted share. The variance between the periods largely is attributable to a 20 percent decline in realized oil and natural gas liquids (NGL) prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling activity, partially offset by a 20 percent increase in production, lower production and ad valorem taxes, lower effective tax rate, and decreased net general and administrative expenses (G&A).[See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.]
Energen’s adjusted EBITDAX totaled $204.4 million in the 3rd quarter of 2015, up 2 percent from adjusted EBITDAX from continuing operations in the same period last year of $199.9 million.[See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.] |
The company’s adjusted 3rd quarter earnings exceeded internal expectations by more than 50 percent largely due to the impact of decreased stock-based compensation on G&A expenses, lower-than-expected lease operating, marketing and transportation expenses (LOE), increased production, and lower production and ad valorem taxes, partially offset by lower commodity prices and higher DD&A. Production in the 3rd quarter of 2015 exceeded the guidance range midpoint by 2 percent (approximately 1,200 boepd) primarily due to better-than-expected well performance from Wolfcamp wells in the Delaware Basin.
“Exciting, positive well results, together with better-than-expected production, expenses, and earnings, underscored Energen’s continued strong performance in the 3rd quarter as a leading operator in the Permian Basin,” said James McManus, Energen’s chairman and chief executive officer.
“We are very pleased with the results of our first two Middle Spraberry wells, both of which were drilled in Martin County. The early results are very solid and have high oil content. We have another Middle Spraberry well in Martin County currently in the early stages of flow back. I believe the Middle Spraberry is another target in the Midland Basin that will add to our existing, extensive inventory of engineered, unrisked locations.
“Our three, 10,000 foot lateral wells in Glasscock County generated very strong 24-hour and peak 30-day average rates from the three Wolfcamp benches targeted. We will be monitoring closely the performance of these wells but believe that the internal rates of return of the Wolfcamp A and B at $60 flat oil prices could be at least 15 percentage points higher than returns on comparable 7,500 foot lateral wells. We are working now to identify how many 10,000 foot lateral wells our acreage can support and will certainly move forward to incorporate as many as we can in our future development plans.
“Our latest Lower Spraberry appraisal well in southern Martin County – together with the cumulative performances of the other Lower Spraberry wells drilled earlier this year in the northern part of our Midland Basin acreage footprint – continue to support this play’s attractive return potential.
“Our development well program in Glasscock County continued to generate solid results in the 3rd quarter, and we continue to see drill-and-complete costs for a 7,500 foot lateral Wolfcamp A well trending down toward $5.6 million. We also have now expanded our development program to Martin County, where we are drilling Lower Spraberry wells along with Wolfcamp A and B.
“As we look ahead to 2016, we will be return-driven, financially disciplined, and flexible. Based on strip prices for 2016 in the January timeframe, we will focus our capital on those projects that generate the highest internal rates of return and at a level of investment that allows us to maintain a debt-to-EBITDAX multiple of 2.0-2.5 times,” McManus said. “Our strong balance sheet provides us with excellent flexibility to adjust as conditions change. We have outstanding assets in the Midland and Delaware Basins that support a rich inventory of opportunities, and we plan to develop those assets in a manner that supports long-term value creation for our shareholders.”
2
3rd Quarter Financial Review
Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
[See “Non-GAAP Financial Measures” beginning on pp 12 for more information]
| 3Q15 | 3Q14 | |||||||||||||||
| $M | $/dil. sh. | $M | $/dil. sh. | |||||||||||||
Net Income/(Loss) All Operations (GAAP) | $ | (227,904 | ) | $ | (2.89 | ) | $ | 457,251 | $ | 6.22 | ||||||
Less: Non-cash mark-to-market gains/(losses) | (784 | ) | (0.01 | ) | 94,142 | 1.28 | ||||||||||
Less: Asset impairments, dry hole expenses | (255,703 | ) | (3.25 | ) | (118,823 | ) | (1.62 | ) | ||||||||
Less: Income/(loss) associated w/ San Juan Basin divestment | (41 | ) | 0.00 | 6,443 | 0.09 | |||||||||||
Less: Discontinued operations | — | �� | 436,620 | 5.94 | ||||||||||||
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Adj. Income Continuing Operations (Non-GAAP) | $ | 28,624 | $ | 0.36 | $ | 38,869 | $ | 0.53 | ||||||||
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Note: Per share amounts may not sum due to rounding
Production from Continuing Operations (excludes production associated with San Juan divestiture)
| Commodity | 3Q15 | 3Q14 | Change | 2Q15 | ||||||||||||||||||||||||
| MBOE | boepd | MBOE | boepd |
| MBOE | boepd | ||||||||||||||||||||||
Oil | 3,610 | 39,239 | 3,011 | 32,728 | 20 | % | 3,595 | 39,505 | ||||||||||||||||||||
NGL | 1,056 | 11,478 | 890 | 9,674 | 19 | % | 1,060 | 11,648 | ||||||||||||||||||||
Natural Gas | 1,227 | 13,337 | 995 | 10,815 | 23 | % | 1,151 | 12,648 | ||||||||||||||||||||
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Total | 5,893 | 64,054 | 4,896 | 53,217 | 20 | % | 5,806 | 63,802 | ||||||||||||||||||||
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Note: Totals may not sum due to rounding
Production from Continuing Operations (excludes production associated with San Juan divestiture)
| Area | 3Q15 | 3Q14 | Change | 2Q15 | ||||||||||||||||||||||||
| MBOE | boepd | MBOE | boepd |
| MBOE | boepd | ||||||||||||||||||||||
Midland Basin | 2,970 | 32,283 | 1,877 | 20,402 | 58 | % | 2,956 | 32,484 | ||||||||||||||||||||
Wolfcamp/Spraberry | 1,944 | 21,130 | 586 | 6,370 | 1,777 | 19,527 | ||||||||||||||||||||||
Wolfberry | 1,026 | 11,152 | 1,291 | 14,033 | 1,179 | 12,956 | ||||||||||||||||||||||
Delaware Basin | 1,519 | 16,511 | 1,524 | 16,565 | 0 | % | 1,449 | 15,923 | ||||||||||||||||||||
3rd Bone Spring/Other | 997 | 10,837 | 1,219 | 13,250 | 963 | 10,582 | ||||||||||||||||||||||
Wolfcamp | 522 | 5,674 | 305 | 3,315 | 486 | 5,341 | ||||||||||||||||||||||
Central Basin Platform | 902 | 9,804 | 998 | 10,848 | (10 | )% | 918 | 10,088 | ||||||||||||||||||||
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Total Permian Basin | 5,391 | 58,598 | 4,399 | 47,815 | 23 | % | 5,323 | 58,495 | ||||||||||||||||||||
San Juan Basin/Other | 502 | 5,457 | 497 | 5,402 | 1 | % | 483 | 5,308 | ||||||||||||||||||||
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Total | 5,893 | 64,054 | 4,896 | 53,217 | 20 | % | 5,806 | 63,802 | ||||||||||||||||||||
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Note: Totals may not sum due to rounding
3
Average Realized Sales Prices from Continuing Operations (excludes production associated with San Juan divestiture)
| Commodity | 3Q15 | 3Q14 | Change | |||||||||
Oil (per barrel) | $ | 71.64 | $ | 84.34 | (15 | )% | ||||||
NGL (per gallon) | $ | 0.25 | $ | 0.71 | (65 | )% | ||||||
Natural Gas (per Mcf) | $ | 3.69 | $ | 3.70 | * | 0 | % | |||||
| * | Prior period hedges were left unallocated for current-year San Juan Basin divestiture; as reported last year, the average realized sales price of natural gas in 3Q14 was $4.27 per Mcf. |
Average Prices from Continuing Operations Before Effects of Hedges (excludes production associated with San Juan divestiture)
| Commodity | 3Q15 | 3Q14 | Change | |||||||||
Oil (per barrel) | $ | 44.47 | $ | 86.34 | (49 | )% | ||||||
NGL (per gallon) | $ | 0.25 | $ | 0.68 | (63 | )% | ||||||
Natural Gas (per Mcf) | $ | 2.29 | $ | 3.69 | (38 | ) % | ||||||
Expenses from Continuing Operations and Excluding San Juan Basin Assets sold March 31, 2015
(per BOE, except interest expense)
| Expenses | 3Q15 | 3Q14 | Change | |||||||||
LOE* | $ | 9.26 | $ | 10.59 | (13 | )% | ||||||
Production & ad valorem taxes | $ | 2.25 | $ | 4.43 | (49 | )% | ||||||
DD&A | $ | 25.17 | $ | 25.05 | 1 | % | ||||||
Net G&A | $ | 3.85 | † | $ | 5.80 | (34 | )% | |||||
Interest ($MM) | $ | 10.1 | $ | 11.5 | (12 | )% | ||||||
| * | Production costs + workovers and repairs + marketing and transportation |
| † | Excludes $0.16 per BOE for pension and pension settlement expenses |
3rd Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)
| • | The success of Energen’s Wolfcamp development program led to a 58 percent increase in Midland Basin production and a 23 percent increase in total Permian Basin production. |
| • | The company’s average realized oil price fell 15 percent to $71.64 per barrel, while the realized price of NGL dropped 65 percent. Excluding the impact of commodity and differential hedges, the average realized price of oil would have been $44.47 per barrel. |
| • | LOE per unit declined 13 percent to $9.26 per barrel largely due to lower workover and repair expense, lower power costs, and lower water disposal costs, partially offset increased equipment rental expenses. Per-unit production and ad valorem taxes declined 49 percent. |
| • | Per-unit DD&A expense was essentially unchanged. |
| • | Per-unit net G&A expense of $3.85 per BOE (excluding pension and pension settlement expenses) declined 34 percent from the same period a year ago largely due decreased stock-based compensation and lower expenses for professional and legal services. |
| • | Interest expense declined 12 percent largely due to a prior year write off of debt issuance costs associated with our $600 million Senior Term Loans. |
4
Liquidity Update
The Fall 2015 redetermination of Energen’s borrowing base resulted in a $200 million reduction in its line of credit. The Company’s new line of credit is $1.4 billion.
As of September 30, 2015, Energen had borrowings of $196.5 million on its line of credit and cash/cash equivalents of $0.7 million, for total liquidity available on the new borrowing base of $1.2 billion. Long-term debt at the end of September totaled $553.6 million.
Midland Basin Development Program Results
Development program wells drilled in 3Q15 (gross/net) | 18/18 | |||
Development program wells completed in 3Q15 (gross/net) | 31/30 | |||
Development program wells awaiting completion at end of 3Q15 (gross/net) | 31/31 | |||
Development program wells awaiting completion at YE15e (gross/net) | 48/48 |
In its 2-well, pad-drilling development program in Glasscock County, Energen tested 18 Wolfcamp A and B wells with lateral lengths of 6,700 feet and 7,500 feet during the 3rd quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 1,050 boepd (76% oil) and peak 30-day average rates (3-stream) of 704 boepd (62% oil). These average rates were generally comparable to the development wells tested in the 2nd quarter and higher than those tested in the 1st quarter; the gassier product mix reflects the area where these wells were drilled. These latest wells used a similar completion design that continues to generate encouraging results as the company works to further enhance the economics of its development program.
Since the development program’s inception in 2014, Energen has tested 75 gross (74 net) wells that generated average peak 24-hour IPs (3-stream) of 959 boepd (80% oil) and peak 30-day average rates (3-stream) of 733 boepd (71% oil). A supplemental slide posted atwww.energen.com shows that the average production from these wells — normalized to a 7,000’ lateral length.
During the 3rd quarter, Energen expanded its development program to Martin County, where it has drilled 27 gross (27 net) Lower Spraberry, Wolfcamp A, and Wolfcamp B wells. Another 10 gross (10 net) wells are slated to be drilled in Martin County in the 4th quarter.
Energen’s total 2015 Midland Basin development program calls for the drilling of 98 gross (97 net) wells in Glasscock and Martin counties. As of September 30, 81 gross (80 net) wells had been drilled to total depth, leaving 17 gross (17 net) wells to be drilled in the 4th quarter. Three development rigs are expected to run in the 4th quarter. No further development well completions are slated in 2015.
The company currently estimates that 48 gross (48 net) wells in the 2015 program will be completed in 2016 including all 37 gross (37 net) Martin County development wells.
5
Midland and Delaware Basin Appraisal Program Results
Energen tested seven new appraisal wells in the Permian Basin during the 3rd quarter of 2015, including three, 10,000 foot lateral wells in Glasscock County and its first two Middle Spraberry wells, both in Martin County.[See locator maps atwww.energen.com]
Midland Basin (3-Stream Results)
Well Name | Zone/ County | Lateral length (ft) | Frac Stages | Peak 24-Hour IP | Peak 30-day Avg. | |||||||||||||||||||||||||||||||||||||||||
| Drilled* | Completed | Boepd | %Oil | %NGL | %Gas | Boepd | %Oil | %NGL | %Gas | |||||||||||||||||||||||||||||||||||||
Cole Ranch 35 #107H | WCA/Glasscock | 10,366 | 9,749 | 46 | 1,385 | 74 | 15 | 11 | 1,145 | 70 | 17 | 13 | ||||||||||||||||||||||||||||||||||
Cole Ranch 35 #207H | WCB/Glasscock | 10,428 | 9,805 | 44 | 1,651 | 65 | 19 | 16 | 1,197 | 64 | 20 | 17 | ||||||||||||||||||||||||||||||||||
Cole Ranch 35 #307H | WCC/Glasscock | 10,366 | 9,924 | 46 | 1,447 | 40 | 36 | 25 | 1,065 | 39 | 36 | 25 | ||||||||||||||||||||||||||||||||||
Dickenson SN 20-17 03 #503H | LSB/Martin | 6,996 | 6,509 | 31 | 963 | 78 | 13 | 10 | 672 | 76 | 14 | 11 | ||||||||||||||||||||||||||||||||||
Dickenson SN 20-17 03 #603H | MSB/Martin | 7,013 | 6,408 | 30 | 790 | 78 | 13 | 9 | 634 | 76 | 14 | 10 | ||||||||||||||||||||||||||||||||||
Jones Holton #601H | MSB/Martin | 7,473 | 7,068 | 33 | 948 | 79 | 12 | 9 | 858 | 79 | 12 | 9 | ||||||||||||||||||||||||||||||||||
| * | Represents distance from vertical departure to toe |
Note: Totals may not foot due to rounding
Energen’s three, 10,000 foot lateral wells drilled in Glasscock County generated very strong 24-hour and average 30-day peak rates from the Wolfcamp A, Wolfcamp B, and Wolfcamp C. These three wells averaged a peak 30-day average rate of more than 1,135 boepd, with the oil content ranging from 70 percent in the Wolfcamp A to 64 percent in the Wolfcamp B to 39 percent in the Wolfcamp C.
Energen also tested its first two Middle Spraberry wells, both of which were drilled in different areas of Martin County. The early results of these two wells are very strong, with high oil content and modest declines from their peak 24-hour rates to their peak 30-day average rates.
The company’s most recent Lower Spraberry appraisal well was drilled in southern Martin County near the heart of a vertical Spraberry field. It generated a strong peak 24-hour IP rate of 963 boepd (78% oil) and a peak 30-day average rate of 672 boepd (76% oil). The strength of this well suggests that the company’s exposure to areas of the greatest Spraberry depletion associated with older vertical drilling is limited to approximately 2,000 net acres in northern Midland County (as compared with an earlier estimate of 5,000 net acres).
Together with the cumulative performances of the four Lower Spraberry wells drilled earlier this year in Martin, Midland, and Howard counties, this well further supports the attractive return potential of the Lower Spraberry in the northern part of Energen’s acreage footprint in the Midland Basin.[See cumulative oil performance over time and potential economics of the company’s four northern Midland Basin Lower Spraberry wells atwww.energen.com]
6
Energen currently is drilling its last of 8 gross (8 net) Wolfcamp shale wells in its Midland Basin appraisal program for 2015 — a Wolfcamp A test in Midland County. The final six Spraberry wells in the 2015 appraisal program are in various stages of completion and flow back; three are in Glasscock County and three in Martin County.
Delaware Basin (3-Stream Results)
Well Name | Zone/ County | Lateral length (ft) | Frac Stages | Peak 24-Hour IP | Peak 30-day Avg. | |||||||||||||||||||||||||||||||||||||||||||
| Drilled* | Completed | Boepd | %Oil | %NGL | %Gas | Boepd | %Oil | %NGL | %Gas | |||||||||||||||||||||||||||||||||||||||
Falcon State 28-36 #1H | WCA/Winkler | 4,895 | 4,389 | 21 | 1,049 | 74 | 14 | 12 | 818 | 75 | 13 | 12 | ||||||||||||||||||||||||||||||||||||
| * | Represents distance from vertical departure to toe |
The last of 8 gross (8 net) appraisal wells in Energen’s 2015 Delaware Basin drilling program was the Falcon State 28-36 #1H. Drilled into the Wolfcamp A in Winkler County in the northeastern portion of the Texas Delaware Basin, the well generated strong early results with a peak 24-hour IP of 1,049 (74% oil) and peak 30-day average of 818 boepd (75% oil).
San Juan Basin Mancos Appraisal Program
Energen currently is drilling its fourth Mancos oil formation appraisal well in the San Juan Basin. The first two wells are currently flowing back, and a third well currently is completing. The first two wells were drilled in Rio Arriba County; the others are located in San Juan County. The company plans to drill and complete 7 gross (7 net) wells by year-end 2015; an eighth planned well will be drilled and completed in early 2016. These wells are designed to test the company’s 91,000 net acres with Mancos oil potential.
Capital, Production, and Financial Guidance
Energen today said its 2015 drilling and development capital is now estimated to be $1.0 billion, or $43 million lower than the prior estimate. This is largely the result of the addition of three net Lower Spraberry development wells, a decrease in development program costs, and other miscellaneous adjustments.
The company’s production guidance range for the year remains 22.2 - 23.2 MMBOE (60,882-63,622 boepd), with a midpoint of 22.7 MMBOE (62,252 boepd). This reflects an increase of approximately 19 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE (52,320 boepd).
7
2015 Capital Summary
| 2015e Capital ($MM) | Operated Wells to Be Drilled | |||||||||||
| Gross (Net) | ||||||||||||
Midland Basin | $ | 810 | 125 | (123 | ) | |||||||
Wolfcamp | ||||||||||||
Development | 460 | 83 | (82 | ) | ||||||||
Appraisal | 66 | 8 | (8 | ) | ||||||||
Spraberry | ||||||||||||
Development | 90 | 15 | (15 | ) | ||||||||
Appraisal | 83 | 12 | (12 | ) | ||||||||
Wolfberry | 16 | 7 | (6 | ) | ||||||||
SWD/Facilities | 84 | |||||||||||
Non-operated/Other | 11 | |||||||||||
Delaware Basin | $ | 135 | 14 | (13 | ) | |||||||
Bone Spring | 17 | 3 | (2 | ) | ||||||||
Wolfcamp | 69 | 8 | (8 | ) | ||||||||
Wolfbone | 15 | 3 | (3 | ) | ||||||||
SWD/Facilities | 26 | |||||||||||
Non-operated/Other | 8 | |||||||||||
Other Permian | $ | 6 | 0 | (0 | ) | |||||||
Waterflood injectors | 0 | |||||||||||
Facilities/C02 | 0 | |||||||||||
Non-operated/Other | 6 | |||||||||||
San Juan Basin/Other | $ | 60 | 7 | (7 | ) | |||||||
Mancos | 30 | 7 | (7 | ) | ||||||||
Facilities | 13 | |||||||||||
Non-operated/Other | 17 | |||||||||||
Net Carry/ARO/Other | $ | (9 | ) | |||||||||
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Drilling & Development | $ | 1,002 | 146 | (143 | ) | |||||||
Acquisitions/Lease | $ | 66 | ||||||||||
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Total Capital | $ | 1,068 | ||||||||||
Note: “Facilities” capital includes artificial lift and central gathering facilities; “Other”
Capital includes payadds and refracs
Production by Product (Excluding San Juan Basin Divestiture)
| Commodity | 2015e Midpoint | 2014 | % | |||||||||||||||||
| MMBOE | boepd | MMBOE | boepd | |||||||||||||||||
Oil | 14.3 | 39,126 | 11.8 | 32,323 | 21 | % | ||||||||||||||
NGL | 4.0 | 10,847 | 3.4 | 9,337 | 16 | % | ||||||||||||||
Natural Gas | 4.5 | 12,279 | 3.9 | 10,660 | 15 | % | ||||||||||||||
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Total Continuing Operations | 22.7 | 62,252 | 19.1 | 52,320 | 19 | % | ||||||||||||||
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NOTE: Totals may not sum due to rounding
8
Production by Play (Excluding San Juan Basin Divestiture)
| Area | 2015e Midpoint | 2014 | Change (boepd) | |||||||||||||||||
| MMBOE | boepd | MMBOE | boepd |
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Midland Basin | 11.8 | 32,373 | 7.4 | 20,293 | 60 | % | ||||||||||||||
Wolfcamp/Spraberry | 7.7 | 21,142 | 2.1 | 5,827 | ||||||||||||||||
Wolfberry | 4.1 | 11,230 | 5.3 | 14,466 | ||||||||||||||||
Delaware Basin | 5.4 | 14,764 | 5.8 | 15,995 | (8 | )% | ||||||||||||||
3rd Bone Spring/Other | 3.7 | 10,038 | 4.6 | 12,731 | ||||||||||||||||
Wolfcamp | 1.7 | 4,726 | 1.2 | 3,264 | ||||||||||||||||
Central Basin Platform | 3.6 | 9,910 | 4.1 | 11,104 | (11 | )% | ||||||||||||||
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Total Permian Basin | 20.8 | 57,047 | 17.3 | 47,392 | 20 | % | ||||||||||||||
San Juan Basin/Other | 1.9 | 5,205 | 1.8 | 4,929 | 6 | % | ||||||||||||||
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Total | 22.7 | 62,252 | 19.1 | 52,320 | 19 | % | ||||||||||||||
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NOTE: Totals may not sum due to rounding
Production by Basin/Quarter (Excluding San Juan Divestiture)
| Basin | 1Q15a | 2Q15a | 3Q15a | 4Q15e Midpoint | ||||||||||||||||||||||||||||
| MMBOE | boepd | MMBOE | boepd | MMBOE | boepd | MMBOE | boepd | |||||||||||||||||||||||||
Midland Basin | 2.3 | 25,778 | 3.0 | 32,484 | 3.0 | 32,283 | 3.6 | 38,804 | ||||||||||||||||||||||||
Delaware Basin | 1.2 | 13,611 | 1.4 | 15,923 | 1.5 | 16,511 | 1.2 | 13,000 | ||||||||||||||||||||||||
Central Basin Platform/Other | 0.9 | 10,100 | 0.9 | 10,088 | 0.9 | 9,804 | 0.9 | 9,652 | ||||||||||||||||||||||||
San Juan Basin/Other | 0.4 | 4,611 | 0.5 | 5,308 | 0.5 | 5,457 | 0.5 | 5,435 | ||||||||||||||||||||||||
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Total Production | 4.9 | 54,100 | 5.8 | 63,802 | 5.9 | 64,054 | 6.2 | 66,891 | ||||||||||||||||||||||||
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NOTE: Totals may not sum due to rounding
Production by Commodity/Quarter (Excluding San Juan Basin Divestiture)
| Commodity | 1Q15a | 2Q15a | 3Q15a | 4Q15e Midpoint | ||||||||||||||||||||||||||||
| MMBOE | boepd | MMBOE | boepd | MMBOE | boepd | MMBOE | boepd | |||||||||||||||||||||||||
Oil | 3.2 | 35,922 | 3.6 | 39,505 | 3.6 | 39,239 | 3.8 | 41,772 | ||||||||||||||||||||||||
NGL | 0.7 | 8,133 | 1.1 | 11,648 | 1.1 | 11,478 | 1.1 | 12,087 | ||||||||||||||||||||||||
Gas | 0.9 | 10,044 | 1.2 | 12,648 | 1.2 | 13,337 | 1.2 | 13,033 | ||||||||||||||||||||||||
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Total Production | 4.9 | 54,100 | 5.8 | 63,802 | 5.9 | 64,054 | 6.2 | 66,891 | ||||||||||||||||||||||||
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NOTE: Totals may not sum due to rounding
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4Q15 AND CY15 FINANCIAL GUIDANCE
Energen’s estimated expenses, excluding San Juan Basin divestiture, are as follows:
| Per BOE, except where noted | 4Q15 | CY15 | ||
LOE (production costs, marketing & transportation) | $9.75-$10.15 | $9.50-$10.10 | ||
Production & ad valorem taxes (% of revenues, excluding hedges) | 7.8% | |||
DD&A expense* | $23.75-$24.25 | $24.55-$25.60 | ||
General & administrative expense, net† | $4.60-$5.00 | $5.00-$5.50 | ||
Exploration expense (seismic, delay rentals, etc.) | $0.80-$0.90 | $0.40-$0.50 | ||
Interest expense ($MM) | $9.5-$10.5 | $40.0-$46.0 | ||
FF&E ($MM) | $1.5-$1.9 | $6.0-$6.4 | ||
Accretion of discount on ARO ($MM) | $1.5-$1.9 | $6.5-$6.9 | ||
Effective tax rate (%) | 34-36% | 33-35% | ||
| * | Subject to year-end, 4th quarter, look-back adjustment |
| † | Excludes $5.19 per BOE in 4Q15 and $1.63 per BOE in CY15 for pension and pension settlement expenses. |
4Q15 Hedges
The company’s hedge position for the last three months of 2015 is:
Commodity | Hedge Volumes | Production @ Midpoint | Hedge % | NYMEXe Price | ||||||||||||
Oil | 3.5 MMBO | 3.8 MMBO | 91 | % | $ | 78.28 per barrel | ||||||||||
Natural Gas | 7.0 Bcf | 7.2 Bcf | 97 | % | $ | 4.25 per Mcf | ||||||||||
NGL | — | 1.1 MMBOE | — | — | ||||||||||||
Note: Known actuals included
In the table above, basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen’s assumed basis differentials.
Average realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect estimated 4thquarter oil transportation charges of $2.22 per barrel; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin for the remainder of the year.
Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.5 million barrels of oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet oil) differential for 1.9 million barrels at an average price of -$4.55 per barrel. Energen estimates that approximately 80 percent of its oil production for the remainder of the year will be sweet. Gas basis assumptions for all open contracts (November-December) are -$0.09 per Mcf (basis actuals in October were approximately -$0.14 per Mcf).
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Energen’s assumptions for the commodity prices of unhedged production for the remainder of 2015 are $48.35 per barrel of oil (October-December), $2.57 per Mcf of gas (November-December), and $0.47 per gallon of NGL (October-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (October-December) are +$0.34 and +$0.40, respectively. Every 1-cent change in the average price of NGL from $0.47 per gallon is estimated to have a cash flows impact of approximately $300,000.
Energen estimates that price realizations in the 4th quarter of 2015 (pre-hedge) will be approximately:
| • | Crude oil (% of NYMEX/WTI) 94% |
| • | Natural gas (% of NYMEX/Henry Hub) 87% |
| • | NGL (after T&F) (% of NYMEX/WTI) 27% |
Conference Call
Energen will hold its quarterly conference call Friday, November 6, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-877-407-8289 (reference Energen earnings call). A live audio Webcast of the program as well as a replay may be accessed through Web site,www.energen.com.
Energen Corporation is an oil and gas exploration and production company with headquarters in Birmingham, Alabama. The company has 1.1 billion barrels of oil-equivalent proved, probable, and possible reserves and another 2.2 billion barrels of oil-equivalent contingent resources. These all-domestic reserves and resources are located primarily in the Permian Basin in west Texas. For more information, go tohttp://www.energen.com.
FORWARD LOOKING STATEMENT: 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 timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, 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 filing. 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 our forward-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.
Financial, operating, and support data pertaining to all reporting periods included in this release are unaudited and subject to revision.
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