BIRMINGHAM, Ala.--(BUSINESS WIRE)--Energen Corporation (NYSE: EGN) has tested five new Wolfcamp exploratory wells in the Permian Basin, including a Ward County Wolfcamp B well in the Delaware Basin that generated an outstanding peak 24-hour IP rate of just under 1,900 barrels of oil equivalent per day (boepd) and had a 3-stream product mix that was 78 percent oil. The company’s first Wolfcamp A test in Howard County in the Midland Basin also posted strong rates, as did a second Wolfcamp A test in Martin County. (See locator maps at www.energen.com).
In addition to the exploratory wells, Energen has drilled 19 gross (18 net) wells through June 30 as part of its Wolfcamp development program in southern Glasscock County. The two A-bench and two B-bench wells on production in the second quarter are performing above internal expectations. The four wells generated average peak 24-hour IP rates and peak 30-day average rates (3-stream) of 1,237 boepd and 794 boepd, respectively.
In the San Juan Basin, Energen is a 50 percent non-operated participant in four oil wells that have been drilled this year by WPX Energy in the Mancos formation in south-central San Juan Basin. The first two wells are producing, and the results suggest that this horizontal oil play in northern New Mexico could generate returns that compete with Energen’s extensive opportunity set in the Permian Basin.
The peak 24-hour IP rates (3-phase) of the wells were 914 boepd and 1,155 boepd; oil comprised 78 percent and 62 percent, respectively. The average peak 20-day rates were 766 boepd and 752 boepd. Neither well was on gas lift during testing.
“We still want to see how the next two wells perform but are very encouraged by our on-going analysis of these first two wells and increasingly optimistic that Energen could well have a viable, horizontal oil play in the San Juan Basin,” said James McManus, Energen’s chairman and chief executive officer. “We likely will deploy a drilling rig in the San Juan Basin in 2015 to begin testing our approximately 75,000 net acres with potential in the oil window of the Mancos formation.”
Utility Sale Receives Approval from Alabama Regulators
In a unanimous decision, the three-member Alabama Public Service Commission last week approved the sale of Energen’s natural gas utility, Alagasco, to The Laclede Group. The transaction, valued at $1.6 billion, including $1.28 billion of cash and approximately $320 million of utility debt, is on track to close by September 30, 2014.
Energen estimates that its after-tax proceeds will be $1.1 billion, after consideration of accelerated intangible drilling costs, and it plans to use those proceeds to reduce short-term indebtedness. The company’s enhanced financial capacity will be used to help fund its future oil- and NGL-focused drilling plans.
Earnings Overview
For the 3 months ended June 30, 2014, Energen reported a consolidated net loss from all operations (GAAP) of $8.0 million, or $0.11 per diluted share. After adjusting for non-cash items and discontinued operations, Energen’s adjusted income from continuing operations in the second quarter of 2014 totaled $35.0 million, or $0.48 per diluted share. This compares with adjusted income from continuing operations in the second quarter of 2013 of $46.9 million, or $0.65 per diluted share.
NOTE: The earnings of Energen’s utility subsidiary, Alabama Gas Corporation, are reflected as discontinued operations due to the pending sale of the utility.
Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
(See “Non-GAAP Financial Measures” beginning on pp. 16 for more information)
| 2Q14 | 2Q13 | |||||||||||||||||||
| $M | $/dil. sh. | $M | $/dil. sh. | |||||||||||||||||
| Net Income All Operations (GAAP) | $ | (7,953 | ) | $ | (0.11 | ) | $ | 83,067 | $ | 1.15 | ||||||||||
| Less: Non-cash Mark-to-Market gain/(loss) | (38,131 | ) | (0.52 | ) | 35,486 | 0.49 | ||||||||||||||
| Adjusted Net Income All Operations (Non-GAAP) | $ | 30,178 | $ | 0.41 | $ | 47,581 | $ | 0.66 | ||||||||||||
| Less: Discontinued Operations | ||||||||||||||||||||
| Gain (Loss) on Disposal of E&P Assets | -- | -- | -- | -- | ||||||||||||||||
| Income (Loss) from E&P Discontinued Operations | 97 | (0.00 | ) | 2,453 | 0.03 | |||||||||||||||
| Income (Loss) from Utility Discontinued Operations | (4,896 | ) | (0.07 | ) | (1,808 | ) | (0.02 | ) | ||||||||||||
| Adj. Income Continuing Operations (Non-GAAP) | $ | 34,977 | $ | 0.48 | $ | 46,936 | $ | 0.65 | ||||||||||||
|
Note: Per share amounts may not sum due to rounding |
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In comparing the second quarter of 2014 with the prior-year period, the benefits of a 14 percent increase in oil and NGL production were more than offset by higher depreciation, depletion, and amortization (DD&A) expense, a 4 percent decline in realized oil prices largely due to a wider WTI Midland to WTI Cushing differential, increased production expenses, marketing, and transportation (collectively, lease operating expense, or LOE), higher production and ad valorem taxes, and increased net general and administrative (G&A) expenses.
The company met its internal expectations for the second quarter, as the benefit of approximately 300,000 BOE of increased production was essentially offset by higher DD&A expense, increased production and ad valorem taxes, and lower realized commodity prices.
Energen’s adjusted EBITDAX from continuing operations totaled $204.1 million in the second quarter of 2014, up approximately 2 percent from $200.3 million in the same period last year. (See “Non-GAAP Financial Measures” beginning on pp 16 for more information and reconciliation.)
Wolfcamp Shale Exploration Results
MIDLAND BASIN WOLFCAMP EXPLORATORY WELLS
| Well |
Zone/
County |
Lateral length |
Frac |
Peak 24-Hour IP | Peak 30-day Average | |||||||||||||||||||||||||||||||
| Drilled* | Completed | Boepd |
Oil |
NGL |
Gas |
Boepd |
Oil |
NGL |
Gas |
|||||||||||||||||||||||||||
|
Smith |
A/
Howard |
7,500’ | 6,930’ | 28 | 955 | 804 | 88 | 377 | 868 | 726 | 83 | 355 | ||||||||||||||||||||||||
|
Wilbanks |
A/
Martin |
7,500’ | 6,930’ | 28 | 970 | 769 | 117 | 505 | 745 | 608 | 80 | 343 | ||||||||||||||||||||||||
|
Daniel |
A/
Glasscock |
8,150’ | 7,699 | 31 | 775 | 630 | 88 | 338 | 594 | 468 | 77 | 294 | ||||||||||||||||||||||||
|
* Represents distance from vertical departure to toe |
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Energen’s first Wolfcamp exploratory well in Howard County had a completed lateral length of 6,930 feet and generated one of the highest IP rates publicly reported to-date for an A-bench well in Howard County. The Smith SN 48-37 #101H generated a peak 24-hour IP (3-stream) of 955 boepd and a peak 30-day average rate of 868 boepd. The product stream was very “oily,” with a mix of 84% oil, 9% NGL, and 7% gas for both test periods.
The company also tested its second Wolfcamp A well in Martin County, approximately 15 miles east of its Jones-Holton well. The Wilbanks SN 16-15 #101H had a completed lateral length of 6,930 feet and generated a solid peak 24-hour IP (3-stream) of 970 boepd (79% oil, 12% NGL, and 9% gas). The Wilbanks tested at a peak 30-day average of 745 boepd (82% oil, 11% NGL, and 7% gas).
In southern Glasscock County, the Daniel SN 10-3 #101H tested the Wolfcamp A at a 24-hour peak IP of 775 boepd (81% oil, 11% NGL, and 8% gas). The peak 30-day average rate was 594 boepd (79% oil, 13% NGL, and 8% gas).
Energen currently is testing multiple sections of a Cline well drilled on the Eastern Shelf in Glasscock County. Another Cline test, this one in Martin County, is completing. Other exploratory wells under way in the Midland Basin include A- and B-bench wells in Martin County and B- and C-bench tests in southern Glasscock County.
Energen also plans to test the Lower Spraberry formation in the Midland Basin in late 2014. One Lower Spraberry well is slated to be drilled in Martin County late in the 3rd quarter and the other in Midland County late in the fourth quarter. The company expects to test the Lower Spraberry in Glasscock County in early 2015.
Energen’s 2014 Midland Basin exploratory drilling plans include a total of 22 gross (21 net) wells: eight Wolfcamp A wells, five Wolfcamp B wells, four Wolfcamp C wells, three Cline wells, and two Lower Spraberry wells. Three of these wells are scheduled to be drilled to lateral lengths of 10,000 feet and test the A, B, and C benches of the Wolfcamp in southern Glasscock County.
DELAWARE BASIN
| Well |
Zone/
County |
Lateral length |
Frac |
Peak 24-Hour IP |
Peak 30-day Average |
|||||||||||||||||||||||||||||||
| Drilled* | Completed | Boepd |
Oil |
NGL |
Gas |
Boepd |
Oil |
NGL |
Gas |
|||||||||||||||||||||||||||
|
University |
B/
Ward |
5,500 | 4,808 | 20 | 1,896 | 1,483 | 214 | 1,191 | 1,081 | 797 | 147 | 819 | ||||||||||||||||||||||||
|
* Represents distance from vertical departure to toe |
||||||||||||||||||||||||||||||||||||
| Well |
Zone/
County |
Lateral length |
Frac |
Peak 24-Hour IP | Peak 20-day Average | |||||||||||||||||||||||||||||||
| Drilled* | Completed | Boepd |
Oil |
NGL |
Gas |
Boepd |
Oil |
NGL |
Gas |
|||||||||||||||||||||||||||
|
Enterprise |
B/
Reeves |
4,750’ | 4,237’ | 18 | 634 | 191 | 164 | 1,669 | 553 | 131 | 157 | 1,595 | ||||||||||||||||||||||||
|
* Represents distance from vertical departure to toe |
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Energen’s latest “east side” well in the Delaware Basin tested the B bench of the Wolfcamp in Ward County and generated top-tier rates. The University 16-17 #1H generated a peak 24-hour IP (3-stream) of 1,896 boepd (78% oil, 11% NGL, and 11% gas) and a peak 30-day average rate of 1,081 boepd (74% oil, 14% NGL, and 12% gas).
In Reeves County, Energen’s latest Wolfcamp B test produced at lower rates than the company’s other Reeves County Wolfcamp wells, including the near-by E.J. Brady well. Company engineers and geologists continue to monitor and analyze the performance of the Enterprise C19-5 #1H but think the lateral may not have been optimally landed. The Enterprise well generated a peak 24-hour IP (3-stream) of 634 boepd (30% oil, 26% NGL, and 44% gas) and a peak 20-day average rate of 553 boepd (24% oil, 28% NGL, and 48% gas).
Energen currently is completing its first Wolfcamp C well in Reeves County; three other Reeves County wells targeting the Wolfcamp A and B benches are drilling or flowing back.
The company plans to test a second C-bench well in Reeves County later in the year; Energen also plans to test longer lateral lengths of 7,500 feet in the Delaware Basin with two wells to be drilled this year in Ward County.
Energen’s 2014 Delaware Basin Wolfcamp drilling plans now include a total of 15 gross (14 net) wells: five Wolfcamp A wells, six Wolfcamp B wells, two Wolfcamp C wells, and two to be determined.
Mancos Formation Results
| Well |
Target
Zone |
Completed
Lat. Length |
Frac |
Peak 24-Hour IP (3-phase) | Peak 20-day Average (3-phase) | ||||||||||||||||||||||||||||
| Boepd |
Oil |
NGL |
Gas |
Boepd |
Oil |
NGL |
Gas |
||||||||||||||||||||||||||
|
Chaco |
Mancos | 4,518 | 14 | 1,155 | 717 | 225 | 1,275 | 752 | 466 | 147 | 829 | ||||||||||||||||||||||
|
Chaco |
Mancos | 4,485’ | 14 | 914 | 709 | 101 | 626 | 766 | 594 | 85 | 525 | ||||||||||||||||||||||
|
Note: Wells not on gas lift during testing period |
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Energen is very pleased with the results of two Mancos formation wells drilled and operated by WPX Energy in the San Juan Basin in New Mexico; Energen has a 50 percent non-operated interest in these wells. The Chaco 2308-09A #145H and #146H wells targeted the Mancos formation at vertical depths of approximately 5,500-5,800 feet.
The #145H generated a peak 24-hour IP (3-stream) of 1,155 boepd (62% oil, 20% NGL, and 18% gas) and a peak 20-day average rate (3-stream) of 752 boepd (62% oil, 20% NGL, and 18% gas). The #146H tested at a peak 24-hour IP (3-stream) of 914 boepd (78% oil, 11% NGL, and 11% gas) and at a peak 20-day average rate (3-stream) of 766 boepd (78% oil, 11% NGL, and 11% gas).
Wolfcamp Shale Development Program Results
Through the first half of 2014, Energen has drilled 19 gross (18 net) wells in its Wolfcamp development program in southern Glasscock County. Four wells with sufficient production history – 2 of which are A-bench laterals and 2 are B-bench laterals – have generated average peak 24-hour IP rates (3-stream) of 1,237 boepd (87% oil, 7% NGL, and 6% gas) and average peak 30-day average rates of 794 boepd (78% oil, 12% NGL, and 10% gas). Energen plans to drill 57 gross (55 net) wells – Wolfcamp A and Wolfcamp B stacked laterals – in 2014.
During the second quarter, Energen realized spud-to-total depth drill times of as few as 14 days; however, a drill pipe-related issue in one well led to a significant delay in the timing of completions for a group of adjacent wells. As a result, production from the development program in 2014 is estimated to be negatively affected by approximately 500,000 BOE, primarily in the third quarter. Total annual production is not expected to be affected largely due to better-than-expected year-to-date production and anticipated increases in vertical Wolfberry production.
Second Quarter Earnings Detail
As noted previously, Energen’s adjusted income from continuing operations in the second quarter of 2014 totaled $35.0 million, or $0.48 per diluted share, down from $46.9 million, or $0.65 per diluted share, in the same period last year. The benefits of a 14 percent increase in oil and NGL production were more than offset by higher DD&A expense, a 4 percent decline in realized oil prices largely due to a wider WTI Midland to WTI Cushing differential, increased LOE, greater production and ad valorem taxes, and higher G&A expenses.
Production by Commodity (MBOE)
| Commodity | 2Q14 | 2Q13 | Change | ||||||||||||
| Continuing Operations | |||||||||||||||
| Oil | 2,833 | 2,592 | 9 % | ||||||||||||
| NGL | 1,065 | 815 | 31 % | ||||||||||||
| Natural Gas | 2,446 | 2,457 | (0) % | ||||||||||||
| Total Continuing Operations | 6,344 | 5,864 | 8 % | ||||||||||||
Production from Continuing Operations by Area (MBOE)
| Area | 2Q14 | 2Q13 | Change | ||||||||||||
| Midland Basin | 1,755 | 1,223 | 43 % | ||||||||||||
| Wolfberry | 1,371 | 1,221 | |||||||||||||
| Wolfcamp/Cline | 384 | 2 | |||||||||||||
| Delaware Basin | 1,488 | 1,190 | 25 % | ||||||||||||
| 3rd Bone Spring/Other | 1,201 | 1,098 | |||||||||||||
| Wolfcamp | 287 | 92 | |||||||||||||
| Central Basin Platform | 1,060 | 1,136 | (7) % | ||||||||||||
| Total Permian Basin | 4,303 | 3,549 | 21 % | ||||||||||||
| San Juan Basin/Other | 2,041 | 2,315 | (12) % | ||||||||||||
| Total Continuing Operations | 6,344 | 5,864 | 8 % | ||||||||||||
Average Realized Sales Prices from Continuing Operations
| Commodity | 2Q14 | 2Q13 | Change | |||||||||||||||||
| Oil (per barrel) | $ | 83.65 | $ | 87.11 | (4) % | |||||||||||||||
| NGL (per gallon) | $ | 0.70 | $ | 0.70 | 0 % | |||||||||||||||
| Natural Gas (per Mcf) | $ | 4.25 | $ | 4.19 | 1 % | |||||||||||||||
Oil production in the second quarter increased 9 percent year-over-year as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins more than offset declines in the mature Central Basin Platform. NGL production increased 31 percent year-over-year largely due to less ethane rejection and new horizontal Wolfcamp drilling. Natural gas production was essentially unchanged, as associated gas production in the Permian Basin was offset by declining San Juan Basin gas production.
The biggest increases in production by play in the second quarter, year-over-year, resulted from horizontal Wolfcamp drilling in the Midland and Delaware basins. The vertical Wolfberry and 3rd Bone Spring also demonstrated improved production; and, as expected, production declined in the mature Central Basin Platform and the San Juan Basin.
Average realized sales prices from continuing operations in the second quarter were essentially flat, year-over-year, with respect to NGL and natural gas. Realized oil prices were lower by 4 percent, primarily due to the impact of wider WTI Midland to WTI Cushing and WTS Midland to WTI Cushing differentials.
In the second quarter of 2014, LOE (i.e., production costs, marketing, and transportation) was essentially unchanged from the same period a year ago at $10.20 per BOE. Per-unit production taxes and ad valorem taxes in the second quarter of 2014 increased approximately 10 percent over the same period in 2013 to $4.42 per BOE.
Per-unit DD&A expense from continuing operations in the second quarter of 2014 totaled $21.31 per BOE, increasing approximately 12 percent from the same period last year largely due to year-over-year increases in development costs.
Per-unit net G&A expense of $5.29 was approximately 12 percent higher than in the same period a year ago largely due to increased salaries and stock-based compensation.
Interest expense in the second quarter of 2014 totaled $8 million, down $2.2 million from the same period last year. This primarily was the result of a reclassification of certain interest expense in each period to discontinued operations. On a per-unit basis, interest expense decreased approximately 28 percent in the second quarter of 2014 (from the same period last year) to $1.26 per BOE.
Year-to-Date Earnings
For the 6 months ended June 30, 2014, Energen reported consolidated net income from all operations (GAAP) of $45.4 million, or $0.62 per diluted share. After adjusting for non-cash items and discontinued operations, Energen’s adjusted income from continuing operations in the year-to-date 2014 totaled $72.2 million, or $0.99 per diluted share. This compares with adjusted income from continuing operations in the year-to-date 2013 of $81.3 million, or $1.12 per diluted share.
Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
(See “Non-GAAP Financial Measures” beginning on pp. 16 for more information)
| YTD14 | YTD13 | |||||||||||||||||
| $M | $/dil. sh. | $M | $/dil. sh. | |||||||||||||||
| Net Income All Operations (GAAP) | $ | 45,363 | $ | 0.62 | $ | 139,759 | $ | 1.93 | ||||||||||
| Less: Non-cash Mark-to-Market gain/(loss) | (59,667 | ) | (0.82 | ) | 9,544 | 0.13 | ||||||||||||
| Adjusted Net Income All Operations (Non-GAAP) | $ | 105,030 | $ | 1.44 | $ | 130,215 | $ | 1.80 | ||||||||||
| Less: Discontinued Operations | ||||||||||||||||||
| Gain (Loss) on Disposal of E&P Assets | (1,050 | ) | (0.01 | ) | -- | -- | ||||||||||||
| Income (Loss) from E&P Discontinued Operations | (1,029 | ) | (0.01 | ) | 4,451 | 0.06 | ||||||||||||
| Income (Loss) from Utility Discontinued Operations | 34,949 | 0.48 | 44,467 | 0.61 | ||||||||||||||
| Adj. Income Continuing Operations (Non-GAAP) | $ | 72,160 | $ | 0.99 | $ | 81,297 | $ | 1.12 | ||||||||||
|
Note: Per share amounts may not sum due to rounding |
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Energen’s adjusted EBITDAX from continuing operations totaled $408.5 million in the year-to-date 2014, up approximately 13 percent from $361.8 million in the same period last year. (See “Non-GAAP Financial Measures” beginning on pp 16 for more information and reconciliation.)
Production by Commodity (MBOE)
| Commodity | YTD14 | YTD13 | Change | ||||||||||||||
| Continuing Operations | |||||||||||||||||
| Oil | 5,584 | 4,906 | 14 % | ||||||||||||||
| NGL | 1,968 | 1,471 | 34 % | ||||||||||||||
| Natural Gas | 4,800 | 4,760 | 1 % | ||||||||||||||
| Total Continuing Operations | 12,352 | 11,137 | 11 % | ||||||||||||||
Production from Continuing Operations by Area (MBOE)
| Area | YTD14 | YTD13 | Change | ||||||||||||||
| Midland Basin | 3,292 | 2,208 | 49 % | ||||||||||||||
| Wolfberry | 2,845 | 2,205 | |||||||||||||||
| Wolfcamp/Cline | 447 | 3 | |||||||||||||||
| Delaware Basin | 2,892 | 2,143 | 35 % | ||||||||||||||
| 3rd Bone Spring/Other | 2,385 | 2,029 | |||||||||||||||
| Wolfcamp | 507 | 114 | |||||||||||||||
| Central Basin Platform | 2,076 | 2,222 | (7) % | ||||||||||||||
| Total Permian Basin | 8,260 | 6,573 | 26 % | ||||||||||||||
| San Juan Basin/Other | 4,092 | 4,564 | (10) % | ||||||||||||||
| Total Continuing Operations | 12,352 | 11,137 | 11 % | ||||||||||||||
Average Realized Sales Prices from Continuing Operations
| Commodity | YTD14 | YTD13 | Change | |||||||||||||||||
| Oil (per barrel) | $ 85.23 | $ 86.42 | (1) % | |||||||||||||||||
| NGL (per gallon) | $ 0.72 | $ 0.73 | (1) % | |||||||||||||||||
| Natural Gas (per Mcf) | $ 4.38 | $ 4.18 | 5 % | |||||||||||||||||
For the six months ending June 30, 2014, per-unit LOE declined approximately 5 percent from the same period a year ago to $10.70 per BOE. Per-unit production taxes and ad valorem taxes in the year-to-date 2014 increased approximately 6 percent over the same period last year to $4.48 per BOE.
Per-unit DD&A expense from continuing operations in the year-to-date 2014 totaled $20.93 per BOE, increasing approximately 13 percent from the same period last year largely due to year-over-year increases in development costs.
Per-unit net G&A expense in the first six months of 2014 totaled $5.32 per BOE, or approximately 6 percent higher than in the same period a year ago.
Interest expense in the year-to-date 2014 totaled $15.9 million, down $4.2 million from the same period last year. This primarily was the result of a reclassification of certain interest expense in each period to discontinued operations. On a per-unit basis, interest expense decreased approximately 29 percent in the first six months of 2014 (from the same period last year) to $1.28 per BOE.
2014 Capital, Production and Financial Guidance Update
Energen has tweaked its capital plans for 2014 to reflect additional projects/changes in scope, increased non-operated working interest, year-to-date acquisitions/unproved leasehold, and other miscellaneous items. Guidance for production from continuing operations remains unchanged at 24.9-25.9 MMBOE, with a midpoint of 25.4 MMBOE; however, a delay in the company’s Midland Basin Wolfcamp development program resulting from a drill pipe-related issue has lowered third-quarter production estimates and altered the contribution by formation to total Midland Basin production.
2014e Capital & Drilling Summary
|
2014e Capital ($ MM) |
Operated Wells Gross (Net) |
||||
| Midland Basin | $ | 870 | 133 (126) | ||
| Wolfcamp/Cline | 665 | 79 (76) | |||
| Wolfberry/Other | 125 | 54 (50) | |||
| Facilities/Other | 80 | ||||
| Delaware Basin | $ | 415 | 42 (38) | ||
| 3(rd) Bone Spring/Other | 185 | 27 (24) | |||
| Wolfcamp | 180 | 15 (14) | |||
| Facilities/Other | 50 | ||||
| Other Permian | $ | 43 | 26 (22)* | ||
| Waterfloods/CO(2) floods | 17 | 26 (22)* | |||
| Facilities/Other | 26 | ||||
| San Juan Basin/Other | $ | 26 | 0 (0) | ||
| Facilities/Other | 26 | ||||
| Acquisitions/Unproved Leasehold YTD | $ | 23 | |||
| Net Carry In/Carry Out | $ | 23 | |||
|
TOTAL – Contg. Ops |
$ |
1,400 |
201 (186) | ||
|
Note: “Facilities” capital includes salt water disposal wells, artificial lift, and central gathering facilities; “Other” capital includes payadds, refracs, and non-operated activities.
* Includes 10 gross (9 net) injectors |
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Production from Continuing Operations by Area (MMBOE)
| Area | 2014e Midpoint | 2013 | ||||||||||||||||||
| Revised | Prior | Original | ||||||||||||||||||
| Midland Basin | 7.6 | 7.7 | 7.4 | 5.1 | ||||||||||||||||
| Wolfcamp/Cline | 2.3 | 2.8 | 2.2 | 0.0 | ||||||||||||||||
| Wolfberry | 5.3 | 4.9 | 5.2 | 5.1 | ||||||||||||||||
| Delaware Basin | 5.6 | 5.6 | 5.4 | 4.7 | ||||||||||||||||
| 3rd Bone Spring/Other | 4.4 | 4.5 | 4.5 | 4.2 | ||||||||||||||||
| Wolfcamp | 1.2 | 1.1 | 0.9 | 0.5 | ||||||||||||||||
| Central Basin Platform | 3.9 | 3.8 | 3.7 | 4.4 | ||||||||||||||||
| Total Permian Basin | 17.1 | 17.1 | 16.5 | 14.2 | ||||||||||||||||
| San Juan Basin/Other | 8.3 | 8.3 | 8.4 | 9.1 | ||||||||||||||||
| Total Continuing Operations | 25.4 | 25.4 | 24.9 | 23.3 | ||||||||||||||||
Production from Continuing Operations by Product (MMBOE)
| Commodity |
2014e |
2013 |
2013 vs Revised 2014e |
||||||||||||
| Oil | 11.6 | 10.4 | 12 % | ||||||||||||
| NGL | 4.1 | 3.2 | 28 % | ||||||||||||
| Natural Gas | 9.7 | 9.7 | -- | ||||||||||||
| Total Continuing Operations | 25.4 | 23.3 | 9 % | ||||||||||||
Production from Continuing Operations by Basin and Product (MMBOE)
| Basin | Oil | NGL | Gas | Total | |||||||||||||||||||||||||
| 2014e | 2013 | 2014e | 2013 | 2014e | 2013 | 2014e | 2013 | ||||||||||||||||||||||
| Midland Basin | 4.5 | 3.2 | 1.6 | 1.0 | 1.5 | 0.9 | 7.6 | 5.1 | |||||||||||||||||||||
| Delaware Basin | 3.4 | 3.1 | 1.0 | 0.7 | 1.2 | 0.9 | 5.6 | 4.7 | |||||||||||||||||||||
| Central Basin Platform/Other | 3.5 | 3.9 | 0.2 | 0.2 | 0.2 | 0.2 | 3.9 | 4.4 | |||||||||||||||||||||
| San Juan Basin/Other | 0.2 | 0.1 | 1.3 | 1.3 | 6.8 | 7.7 | 8.3 | 9.1 | |||||||||||||||||||||
| Total Continuing Operations | 11.6 | 10.4 | 4.1 | 3.2 | 9.7 | 9.7 | 25.4 | 23.3 | |||||||||||||||||||||
|
NOTE: 2014e production reflects the midpoint of guidance |
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Production from Continuing Operations by Basin per Quarter (MMBOE)
| Basin | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||||||||||||||||||||||
| 2014 | 2013 | 2014 | 2013 | 2014e | 2013 | 2014e | 2013 | ||||||||||||||||||||||
| Midland Basin | 1.5 | 1.0 | 1.8 | 1.2 | 1.8 | 1.4 | 2.5 | 1.5 | |||||||||||||||||||||
| Delaware Basin | 1.4 | 1.0 | 1.5 | 1.2 | 1.3 | 1.3 | 1.4 | 1.2 | |||||||||||||||||||||
| Central Basin Platform/Other | 1.0 | 1.1 | 1.1 | 1.1 | 0.9 | 1.1 | 0.9 | 1.1 | |||||||||||||||||||||
| San Juan Basin/Other | 2.1 | 2.2 | 2.0 | 2.3 | 2.1 | 2.3 | 2.1 | 2.2 | |||||||||||||||||||||
| Total Production – Contg Ops | 6.0 | 5.3 | 6.3 | 5.9 | 6.1 | 6.1 | 6.9 | 6.0 | |||||||||||||||||||||
|
NOTE: 2014e production reflects the midpoint of guidance; totals may not sum due to rounding |
|||||||||||||||||||||||||||||
Energen has revised its 2014 guidance for after-tax cash flows and earnings to reflect numerous adjustments including year-to-date results, timing and composition of annual production, increased assumptions for key basis differentials, and reduced interest expense. After-tax cash flows from continuing operations in 2014 are estimated to be $833-$855 million, and earnings are estimated to fall within a range of $2.00-$2.30 per diluted share.
Energen’s estimated expenses from continuing operations in 2014 on a per-BOE basis are:
| Production costs, marketing, and transportation | $ | 10.25 | - | $ | 10.50 | ||||||||||
| Production and ad valorem taxes | $ | 4.20 | - | $ | 4.60 | ||||||||||
| DD&A expense | $ | 21.00 | - | $ | 21.50 | ||||||||||
| General & Administrative expense, net | $ | 4.80 | - | $ | 5.20 | ||||||||||
| Interest expense | $ | 1.50 | - | $ | 1.80 | ||||||||||
| Exploration expense (delay rentals, seismic, G&G, etc.) | $ | 0.90 | - | $ | 1.00 | ||||||||||
Approximately 77 percent of the company’s total estimated midpoint of production from continuing operations for the remainder of 2014 is hedged. Assumed prices applicable to Energen Resources’ unhedged volumes for the remainder of the year are $95.00 per barrel of oil, $0.92 per gallon of NGL, and $4.50 per Mcf of natural gas.
Hedges also are in place that limit the company’s exposure in the second half of 2014 to the Midland to Cushing differential. Energen Resources has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.6 million barrels of oil production at an average price of $3.30 per barrel and the WTI Midland to WTI Cushing differential for 1.2 million barrels at an average price of $3.08 per barrel.
Energen’s 2014 guidance includes assumed prices applicable to Energen Resources’ unhedged oil basis differentials for the remainder of the year (including known actuals). They are $6.00 per barrel (WTS Midland to WTI Cushing, or sour) and $6.00 per barrel (WTI Midland to WTI Cushing, or sweet). Energen estimates that approximately 74 percent of its oil production for the remainder of 2014 will be sweet. Gas basis assumptions (including known actuals) are $0.05 per Mcf in the Permian and San Juan basins.
The company’s current hedge position for the remainder of 2014 is as follows:
|
Commodity |
Hedge Volumes |
2014e ROY Production (Contg Ops) Midpoint |
Hedge % |
NYMEXe Price |
|||||||||||
|
Oil |
5.0 |
MMBO |
6.0 |
MMBO |
82 % |
$ |
92.65 per barrel |
||||||||
|
NGL |
35.8 |
MMgal |
87.7 |
MMgal |
41 % |
$ |
0.93 per gallon |
||||||||
|
Natural Gas |
25.7 |
Bcf |
29.3 |
Bcf |
88 % |
$ |
4.46 per Mcf |
||||||||
|
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 Resources' assumed San Juan and Permian basis differentials.
Average realized oil and gas prices for Energen Resources' 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 oil transportation charges of approximately $2.65 per barrel for the remainder of 2014; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.09 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.
As a result of Energen’s 2014 hedge position for the remainder of the year, changes in commodity prices will have a significantly lessened impact on Energen's 2014 cash flows. Every $1.00 change in the average NYMEX price of oil from $95 per barrel for the remainder of the year represents an estimated net impact of $555,000; every 1-cent change in the average price of NGL from $0.92 per gallon is estimated to be approximately $230,000; and every 10-cent change in the average NYMEX price of gas from $4.50 represents an immaterial impact.
In addition to commodity sensitivities, Energen estimates that, for the last six months of 2014, every $1 change in the Midland to Cushing differentials for sweet and sour oil from $6 per barrel will impact net income by approximately $1.6 million and $0.5 million, respectively.
CONFERENCE CALL
Energen will hold its quarterly conference call Thursday, July 31, 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 approximately 775 million barrels of oil-equivalent proved, probable, and possible reserves and another 2.5 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 to http://www.energen.com.
|
FORWARD LOOKING STATEMENT: This release contains statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. We undertake no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. A more complete discussion of risks and uncertainties that could affect future results of Energen and its subsidiaries is included in the Company's periodic reports filed with the Securities and Exchange Commission. |
|
Financial, operating, and support data pertaining to all reporting periods included in this release are unaudited and subject to revision. |
|
Non-GAAP Financial Measures
Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes certain non-cash mark-to-market derivative financial instruments. Adjusted income from continuing operations further excludes a loss on disposal of discontinued operations and income and losses from discontinued operations. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies. |
|||||||
| Quarter Ended 6/30/2014 | |||||||
| Energen Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
|||||
| Net Income (GAAP) | (8.0 | ) | (0.11 | ) | |||
| Non-cash mark-to-market losses (net of $21.5 tax) | 38.1 | 0.52 | |||||
| Adjusted Net Income from All Operations (Non-GAAP) | 30.2 | 0.41 | |||||
| Loss from discontinued operations (net of $3.0 tax) | 4.8 | 0.07 | |||||
| Adjusted Income from Continuing Operations (Non-GAAP) | 35.0 | 0.48 | |||||
| Quarter Ended 6/30/2013 | |||||||
| Energen Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
|||||
| Net Income (GAAP) | 83.1 | 1.15 | |||||
| Non-cash mark-to-market gains (net of $20.7 tax) | (35.5 | ) | (0.49 | ) | |||
| Adjusted Net Income from All Operations (Non-GAAP) | 47.6 | 0.66 | |||||
| Income from discontinued operations (net of $0.3 tax) | (0.6 | ) | (0.01 | ) | |||
| Adjusted Income from Continuing Operations (Non-GAAP) | 46.9 | 0.65 | |||||
| Year-to-Date Ended 6/30/2014 | |||||||
| Energen Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
|||||
| Net Income (GAAP) | 45.4 | 0.62 | |||||
| Non-cash mark-to-market losses (net of $33.6 tax) | 59.7 | 0.82 | |||||
| Adjusted Net Income from All Operations (Non-GAAP) | 105.0 | 1.44 | |||||
| Loss on disposal of discontinued operations (net of $0.6 tax) | 1.1 | 0.01 | |||||
| Income from discontinued operations (net of $20.6 tax) | (33.9 | ) | (0.47 | ) | |||
| Adjusted Income from Continuing Operations (Non-GAAP) | 72.2 | 0.99 | |||||
| Year-to-Date Ended 6/30/2013 | |||||||
| Energen Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
|||||
| Net Income (GAAP) | 139.8 | 1.93 | |||||
| Non-cash mark-to-market gains (net of $5.6 tax) | (9.5 | ) | (0.13 | ) | |||
| Adjusted Net Income from All Operations (Non-GAAP) | 130.2 | 1.80 | |||||
| Income from discontinued operations (net of $29.9 tax) | (48.9 | ) | (0.68 | ) | |||
| Adjusted Income from Continuing Operations (Non-GAAP) | 81.3 | 1.12 | |||||
| Note: Amounts may not sum due to rounding | |||||||
|
Non-GAAP Financial Measures
Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDAX from continuing operations further excludes a loss on disposal of discontinued operations, certain non-cash mark-to-market derivative financial instruments and a loss from discontinued operations. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies. |
||||||||||||||||
| Reconciliation To GAAP Information | Year-to-Date Ended 6/30 | Quarter Ended 6/30 | ||||||||||||||
| ($ in millions) | 2013 | 2014 | 2013 | 2014 | ||||||||||||
| Energen Net Income (GAAP) | 139.8 | 45.4 | 83.1 | (8.0 | ) | |||||||||||
| Interest expense | 20.1 | 15.9 | 10.2 | 8.0 | ||||||||||||
| Income tax expense | 50.3 | 7.2 | 46.2 | (1.0 | ) | |||||||||||
| Depreciation, depletion and amortization | 207.3 | 260.5 | 112.4 | 136.2 | ||||||||||||
| Accretion expense | 3.4 | 3.7 | 1.7 | 1.9 | ||||||||||||
| Exploration expense | 5.0 | 15.4 | 3.5 | 2.6 | ||||||||||||
| Adjustment for loss on disposal of discontinued operations, net of tax | - | 1.1 | - | - | ||||||||||||
| Adjustment for mark-to-market (gains) losses | (15.1 | ) | 93.3 | (56.1 | ) | 59.6 | ||||||||||
| Adjustment for (income) loss from discontinued operations, net of tax | (48.9 | ) | (33.9 | ) | (0.6 | ) | 4.8 | |||||||||
| Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP) | 361.8 | 408.5 | 200.3 | 204.1 | ||||||||||||
| Note: Amounts may not sum due to rounding | ||||||||||||||||
|
Non-GAAP Financial Measures
After-tax Cash Flows is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes after-tax cash flows are relevant because they are a measure of cash available to fund the Company's capital expenditures, dividends, debt reduction, and other investments. Adjusted after-tax cash flows excluding Alagasco provides a measure of cash flows available to fund the Company's exploration and production activities. |
||||||||||||||||
| Reconciliation To GAAP Information | Years Ended 12/31 | |||||||||||||||
| ($ in millions) | 2012 Actual | 2013 Actual | 2014 Estimate (e) | |||||||||||||
| Energen Resources | 205 | 148 | 146 | 168 | ||||||||||||
| Alabama Gas Corporation (GAAP)* | 49 | 57 | - | - | ||||||||||||
| Consolidated Net Income (GAAP)* | 254 | 205 | 146 | 168 | ||||||||||||
| Depreciation, depletion and amortization | 441 | 558 | 545 | 545 | ||||||||||||
| Deferred income taxes | 124 | 84 | 93 | 93 | ||||||||||||
| Exploratory expense | 17 | 16 | - | - | ||||||||||||
| Other | (34 | ) | 48 | 49 | 49 | |||||||||||
| After-tax Cash Flows (Non-GAAP) | 802 | 911 | 833 | 855 | ||||||||||||
| Changes in assets and liabilities and other adjustments | (66 | ) | 16 | (25 | ) | (25 | ) | |||||||||
| Net Cash Provided by Operating Activities (GAAP) | 736 | 927 | 808 | 830 | ||||||||||||
| Reconciliation To GAAP Information | Years Ended 12/31 | |||||||||||||||
| ($ in millions) | 2012 Actual | 2013 Actual | 2014 Estimate (e) | |||||||||||||
| Net Cash Provided by Operating Activities (GAAP) | 736 | 927 | 808 | 830 | ||||||||||||
| Changes in assets and liabilities and other adjustments | 66 | (16 | ) | 25 | 25 | |||||||||||
| After-tax Cash Flow (Non-GAAP) | 802 | 911 | 833 | 855 | ||||||||||||
| Less: AGC cash flows from operations and other* | (103 | ) | (116 | ) | - | - | ||||||||||
| Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP) | 699 | 795 | 833 | 855 | ||||||||||||
|
* On April 7, 2014, Energen Corporation announced its agreement to sell Alabama Gas Corporation to The Laclede Group, Inc. The transaction is expected to close by year-end. Accordingly, earnings from Alabama Gas Corporation are excluded from the Company's 2014 estimate. |
||||||||||||||||
|
(e) This estimate is a "forward-looking statement" as defined by the Securities and Exchange Commission. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. A discussion of risks and uncertainties, which could affect future results of Energen and its subsidiaries, is included in the Company's periodic reports filed with the Securities and Exchange Commission. |
||||||||||||||||
|
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 3 months ending June 30, 2014 and 2013 |
|||||||||||||||
| 2nd Quarter | |||||||||||||||
| (in thousands, except per share data) | 2014 | 2013 | Change | ||||||||||||
| Revenues | |||||||||||||||
| Oil, natural gas liquids and natural gas sales | $ | 355,852 | $ | 312,400 | $ | 43,452 | |||||||||
| Gain (loss) on derivative instruments, net | (84,846 | ) | 55,244 | (140,090 | ) | ||||||||||
| Loss on sale of assets and other | (909 | ) | (663 | ) | (246 | ) | |||||||||
|
|
|||||||||||||||
| Total revenues | 270,097 | 366,981 | (96,884 | ) | |||||||||||
| Operating Costs and Expenses | |||||||||||||||
| Oil, natural gas liquids and natural gas production | 64,697 | 59,607 | 5,090 | ||||||||||||
| Production and ad valorem taxes | 28,049 | 23,503 | 4,546 | ||||||||||||
| Depreciation, depletion and amortization | 136,244 | 112,384 | 23,860 | ||||||||||||
| Exploration | 2,575 | 3,455 | (880 | ) | |||||||||||
| General and administrative | 33,542 | 27,666 | 5,876 | ||||||||||||
| Accretion of discount on asset retirement obligations | 1,883 | 1,729 | 154 | ||||||||||||
| Total costs and expenses | 266,990 | 228,344 | 38,646 | ||||||||||||
| Operating Income | 3,107 | 138,637 | (135,530 | ) | |||||||||||
| Other Income (Expense) | |||||||||||||||
| Interest expense | (7,964 | ) | (10,182 | ) | 2,218 | ||||||||||
| Other income | 687 | 196 | 491 | ||||||||||||
| Total other expense | (7,277 | ) | (9,986 | ) | 2,709 | ||||||||||
| Income (Loss) From Continuing Operations Before Income Taxes |
(4,170 |
) |
128,651 |
(132,821 |
) |
||||||||||
| Income tax expense (benefit) | (1,016 | ) | 46,229 | (47,245 | ) | ||||||||||
| Income (Loss) From Continuing Operations | (3,154 | ) | 82,422 | (85,576 | ) | ||||||||||
| Discontinued Operations, net of tax | |||||||||||||||
| Income (loss) from discontinued operations | (4,799 | ) | 645 | (5,444 | ) | ||||||||||
| Income (Loss) From Discontinued Operations | (4,799 | ) | 645 | (5,444 | ) | ||||||||||
| Net Income (Loss) | $ | (7,953 | ) | $ | 83,067 | $ | (91,020 | ) | |||||||
| Diluted Earnings Per Average Common Share | |||||||||||||||
| Continuing operations | $ | (0.04 | ) | $ | 1.14 | $ | (1.18 | ) | |||||||
| Discontinued operations | (0.07 | ) | 0.01 | (0.08 | ) | ||||||||||
| Net Income (Loss) | $ | (0.11 | ) | $ | 1.15 | $ | (1.26 | ) | |||||||
| Basic Earnings Per Average Common Share | |||||||||||||||
| Continuing operations | $ | (0.04 | ) | $ | 1.14 | $ | (1.18 | ) | |||||||
| Discontinued operations | (0.07 | ) | 0.01 | (0.08 | ) | ||||||||||
| Net Income (Loss) | $ | (0.11 | ) | $ | 1.15 | $ | (1.26 | ) | |||||||
| Diluted Avg. Common Shares Outstanding | 72,851 | 72,419 | 432 | ||||||||||||
| Basic Avg. Common Shares Outstanding | 72,851 | 72,167 | 684 | ||||||||||||
| Dividends Per Common Share | $ | 0.150 | $ | 0.145 | $ | 0.005 | |||||||||
|
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 6 months ending June 30, 2014 and 2013 |
||||||||||||
| Year-to-date | ||||||||||||
| (in thousands, except per share data) | 2014 | 2013 | Change | |||||||||
| Revenues | ||||||||||||
| Oil, natural gas liquids and natural gas sales | $ | 706,674 | $ | 567,239 | $ | 139,435 | ||||||
| Gain (loss) on derivative instruments, net | (138,237) | 36,288 | (174,525) | |||||||||
| Loss on sale of assets and other | (1,062) | (215) | (847) | |||||||||
|
|
||||||||||||
| Total revenues | 567,375 | 603,312 | (35,937) | |||||||||
| Operating Costs and Expenses | ||||||||||||
| Oil, natural gas liquids and natural gas production | 132,141 | 125,149 | 6,992 | |||||||||
| Production and ad valorem taxes | 55,373 | 46,879 | 8,494 | |||||||||
| Depreciation, depletion and amortization | 260,464 | 207,336 | 53,128 | |||||||||
| Exploration | 15,389 | 4,953 | 10,436 | |||||||||
| General and administrative | 65,715 | 55,752 | 9,963 | |||||||||
| Accretion of discount on asset retirement obligations | 3,726 | 3,416 | 310 | |||||||||
| Total costs and expenses | 532,808 | 443,485 | 89,323 | |||||||||
| Operating Income | 34,567 | 159,827 | (125,260) | |||||||||
| Other Income (Expense) | ||||||||||||
| Interest expense | (15,852) | (20,083) | 4,231 | |||||||||
| Other income | 1,010 | 1,370 | (360) | |||||||||
| Total other expense | (14,842) | (18,713) | 3,871 | |||||||||
| Income From Continuing Operations Before Income Taxes |
19,725 |
141,114 |
(121,389) |
|||||||||
| Income tax expense | 7,232 | 50,273 | (43,041) | |||||||||
| Income From Continuing Operations | 12,493 | 90,841 | (78,348) | |||||||||
| Discontinued Operations, net of tax | ||||||||||||
| Income from discontinued operations | 33,920 | 48,918 | (14,998) | |||||||||
| Loss on disposal of discontinued operations | (1,050) | − | (1,050) | |||||||||
| Income From Discontinued Operations | 32,870 | 48,918 | (16,048) | |||||||||
| Net Income | $ | 45,363 | $ | 139,759 | $ | (94,396) | ||||||
| Diluted Earnings Per Average Common Share | ||||||||||||
| Continuing operations | $ | 0.17 | $ | 1.26 | $ | (1.09) | ||||||
| Discontinued operations | 0.45 | 0.67 | (0.22) | |||||||||
| Net Income | $ | 0.62 | $ | 1.93 | $ | (1.31) | ||||||
| Basic Earnings Per Average Common Share | ||||||||||||
| Continuing operations | $ | 0.17 | $ | 1.26 | $ | (1.09) | ||||||
| Discontinued operations | 0.45 | 0.68 | (0.23) | |||||||||
| Net Income | $ | 0.62 | $ | 1.94 | $ | (1.32) | ||||||
| Diluted Avg. Common Shares Outstanding | 73,031 | 72,329 | 702 | |||||||||
| Basic Avg. Common Shares Outstanding | 72,737 | 72,155 | 582 | |||||||||
| Dividends Per Common Share | $ | 0.30 | $ | 0.29 | $ | 0.01 | ||||||
|
CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of June 30, 2014 and December 31, 2013 |
||||||||
| (in thousands) | June 30, 2014 | December 31, 2013 | ||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and cash equivalents | $ | 1,516 | $ | 2,523 | ||||
| Short-term investments | 42,000 | − | ||||||
| Accounts receivable, net of allowance | 178,721 | 136,334 | ||||||
| Inventories | 12,541 | 11,130 | ||||||
| Assets held for sale as of June 30, 2014 with prior period comparable | 1,154,046 | 1,242,872 | ||||||
| Derivative instruments | 524 | 17,463 | ||||||
| Other current assets | 87,517 | 31,239 | ||||||
| Total current assets | 1,476,865 | 1,441,561 | ||||||
| Property, Plant and Equipment | ||||||||
| Oil and natural gas properties, net | 5,413,727 | 5,087,573 | ||||||
| Other property and equipment, net | 37,869 | 30,515 | ||||||
| Total property, plant and equipment, net | 5,451,596 | 5,118,088 | ||||||
| Noncurrent derivative instruments | 623 | 5,439 | ||||||
| Other assets | 53,025 | 57,124 | ||||||
| TOTAL ASSETS | $ | 6,982,109 | $ | 6,622,212 | ||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
| Current Liabilities | ||||||||
| Long-term debt due within one year | $ | 570,000 | $ | 60,000 | ||||
| Notes payable to banks | 669,000 | 489,000 | ||||||
| Accounts payable | 135,416 | 78,178 | ||||||
| Liabilities related to assets held for sale as of June 30, 2014 with prior period comparable | 767,131 | 831,570 | ||||||
| Derivative instruments | 96,213 | 30,302 | ||||||
| Other current liabilities | 226,978 | 202,175 | ||||||
| Total current liabilities | 2,464,738 | 1,691,225 | ||||||
| Long-term debt | 553,552 | 1,093,541 | ||||||
| Asset retirement obligations | 113,087 | 108,533 | ||||||
| Deferred income taxes | 848,422 | 807,614 | ||||||
| Noncurrent derivative instruments | 21,705 | 398 | ||||||
| Other long-term liabilities | 66,588 | 62,882 | ||||||
| Total liabilities | 4,068,092 | 3,764,193 | ||||||
| Total Shareholders’ Equity | 2,914,017 | 2,858,019 | ||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 6,982,109 | $ | 6,622,212 | ||||
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending June 30, 2014 and 2013 |
|||||||||||||||
| 2nd Quarter | |||||||||||||||
| (in thousands, except sales price and per unit data) | 2014 | 2013 | Change | ||||||||||||
| Oil and Gas Operations | |||||||||||||||
|
Oil, natural gas liquids and natural gas sales from continuing operations |
|||||||||||||||
| Oil | $ | 262,746 | $ | 234,870 | $ | 27,876 | |||||||||
| Natural gas liquids | 31,163 | 20,871 | 10,292 | ||||||||||||
| Natural gas | 61,943 | 56,659 | 5,284 | ||||||||||||
| Total | 355,852 | 312,400 | 43,452 | ||||||||||||
|
|
|||||||||||||||
| Loss on sale of assets and other | $ | (909 | ) | $ | (663 | ) | $ | (246 | ) | ||||||
|
Open non-cash mark-to-market gains (losses) on derivative instruments |
|||||||||||||||
| Oil | $ | (66,172 | ) | $ | 36,680 | $ | (102,852 | ) | |||||||
| Natural gas liquids | 40 | 168 | (128 | ) | |||||||||||
| Natural gas | 6,511 | 19,301 | (12,790 | ) | |||||||||||
| Total | $ | (59,621 | ) | $ | 56,149 | $ | (115,770 | ) | |||||||
| Closed gains (losses) on derivative instruments | |||||||||||||||
| Oil | $ | (25,754 | ) | $ | (9,076 | ) | $ | (16,678 | ) | ||||||
| Natural gas liquids | 159 | 3,109 | (2,950 | ) | |||||||||||
| Natural gas | 370 | 5,062 | (4,692 | ) | |||||||||||
| Total | $ | (25,225 | ) | $ | (905 | ) | $ | (24,320 | ) | ||||||
| Total Revenues | $ | 270,097 | $ | 366,981 | $ | (96,884 | ) | ||||||||
| Production volumes from continuing operations | |||||||||||||||
| Oil (MBbl) | 2,833 | 2,592 | 241 | ||||||||||||
| Natural gas liquids (MMgal) | 44.7 | 34.2 | 10.5 | ||||||||||||
| Natural gas (MMcf) | 14,676 | 14,742 | (66 | ) | |||||||||||
| Production volumes from continuing operations(MBOE) | 6,344 | 5,864 | 480 | ||||||||||||
| Total production volumes (MBOE) | 6,354 | 6,480 | (126 | ) | |||||||||||
| Average realized prices excluding effects of open non-cash mark-to-market derivative instruments* | |||||||||||||||
| Oil (per barrel) | $ | 83.65 | $ | 87.11 | $ | (3.46 | ) | ||||||||
| Natural gas liquids (per gallon) | $ | 0.70 | $ | 0.70 | $ | − | |||||||||
| Natural gas (per Mcf) | $ | 4.25 | $ | 4.19 | $ | 0.06 | |||||||||
| Average realized prices excluding derivative instruments | |||||||||||||||
| Oil (per barrel) | $ | 92.74 | $ | 90.61 | $ | 2.13 | |||||||||
| Natural gas liquids (per gallon) | $ | 0.70 | $ | 0.61 | $ | 0.09 | |||||||||
| Natural gas (per Mcf) | $ | 4.22 | $ | 3.84 | $ | 0.38 | |||||||||
| Other costs per BOE from continuing operations | |||||||||||||||
| Oil, natural gas liquids and natural gas production expenses |
$ |
10.20 |
$ |
10.16 |
$ |
0.04 |
|||||||||
| Production and ad valorem taxes | $ | 4.42 | $ | 4.01 | $ | 0.41 | |||||||||
| Depreciation, depletion and amortization | $ | 21.31 | $ | 19.00 | $ | 2.31 | |||||||||
| Exploration expense | $ | 0.41 | $ | 0.59 | $ | (0.18 | ) | ||||||||
| General and administrative | $ | 5.29 | $ | 4.72 | $ | 0.57 | |||||||||
| Capital expenditures | $ | 322,572 | $ | 349,879 | $ | (27,307 | ) | ||||||||
|
*The presentation of average prices with derivatives is a non-GAAP measure as a means to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally accepted by the investment community. |
|||||||||||||||
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED) |
|||||||||||||||
| Year-to-date | |||||||||||||||
| (in thousands, except sales price and per unit data) | 2014 | 2013 | Change | ||||||||||||
| Oil and Gas Operations | |||||||||||||||
|
Oil, natural gas liquids and natural gas sales from continuing operations |
|||||||||||||||
| Oil | $ | 516,505 | $ | 425,629 | $ | 90,876 | |||||||||
| Natural gas liquids | 59,366 | 39,526 | 19,840 | ||||||||||||
| Natural gas | 130,803 | 102,084 | 28,719 | ||||||||||||
| Total | 706,674 | 567,239 | 139,435 | ||||||||||||
| Loss on sale of assets and other | $ | (1,062 | ) | $ | (215 | ) | $ | (847 | ) | ||||||
|
Open non-cash mark-to-market gains (losses) on derivative instruments |
|||||||||||||||
| Oil | $ | (87,636 | ) | $ | 28 | $ | (87,664 | ) | |||||||
| Natural gas liquids | 327 | 147 | 180 | ||||||||||||
| Natural gas | (5,993 | ) | 14,926 | (20,919 | ) | ||||||||||
| Total | $ | (93,302 | ) | $ | 15,101 | $ | (108,403 | ) | |||||||
| Closed gains (losses) on derivative instruments | |||||||||||||||
| Oil | $ | (40,556 | ) | $ | (1,632 | ) | $ | (38,924 | ) | ||||||
| Natural gas liquids | 355 | 5,591 | (5,236 | ) | |||||||||||
| Natural gas | (4,734 | ) | 17,228 | (21,962 | ) | ||||||||||
| Total | $ | (44,935 | ) | $ | 21,187 | $ | (66,122 | ) | |||||||
| Total Revenues | $ | 567,375 | $ | 603,312 | $ | (35,937 | ) | ||||||||
| Production volumes from continuing operations | |||||||||||||||
| Oil (MBbl) | 5,584 | 4,906 | 678 | ||||||||||||
| Natural gas liquids (MMgal) | 82.7 | 61.8 | 20.9 | ||||||||||||
| Natural gas (MMcf) | 28,800 | 28,560 | 240 | ||||||||||||
| Production volumes from continuing operations(MBOE) | 12,352 | 11,137 | 1,215 | ||||||||||||
| Total production volumes (MBOE) | 12,516 | 12,401 | 115 | ||||||||||||
| Average realized prices excluding effects of open non-cash mark-to-market derivative instruments* | |||||||||||||||
| Oil (per barrel) | $ | 85.23 | $ | 86.42 | $ | (1.19 | ) | ||||||||
| Natural gas liquids (per gallon) | $ | 0.72 | $ | 0.73 | $ | (0.01 | ) | ||||||||
| Natural gas (per Mcf) | $ | 4.38 | $ | 4.18 | $ | 0.20 | |||||||||
| Average realized prices excluding derivative instruments | |||||||||||||||
| Oil (per barrel) | $ | 92.50 | $ | 86.76 | $ | 5.74 | |||||||||
| Natural gas liquids (per gallon) | $ | 0.72 | $ | 0.64 | $ | 0.08 | |||||||||
| Natural gas (per Mcf) | $ | 4.54 | $ | 3.57 | $ | 0.97 | |||||||||
| Other costs per BOE from continuing operations | |||||||||||||||
| Oil, natural gas liquids and natural gas production expenses |
$ |
10.70 |
$ |
11.24 |
$ |
(0.54 |
) |
||||||||
| Production and ad valorem taxes | $ | 4.48 | $ | 4.21 | $ | 0.27 | |||||||||
| Depreciation, depletion and amortization | $ | 20.93 | $ | 18.45 | $ | 2.48 | |||||||||
| Exploration expense | $ | 1.25 | $ | 0.44 | $ | 0.81 | |||||||||
| General and administrative | $ | 5.32 | $ | 5.01 | $ | 0.31 | |||||||||
| Capital expenditures | $ | 594,268 | $ | 634,932 | $ | (40,664 | ) | ||||||||
|
*The presentation of average prices with derivatives is a non-GAAP measure as a means to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally accepted by the investment community. |
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