BIRMINGHAM, Ala.--(BUSINESS WIRE)--Energen Corporation (NYSE: EGN) has tested four new Wolfcamp wells in the Permian Basin, including its first in Martin County, an “A” bench well that generated the highest IP (3-phase) known for a Wolfcamp A well in Martin County. The last two wells in Energen’s 2013 Wolfcamp program in the southern Delaware Basin tested the “A” and “B” benches in Reeves County; they generated strong initial rates and continue to underscore the exciting Wolfcamp potential in the Texas Delaware Basin. [See locator maps at www.energen.com].
On the strength of improved drilling efficiency in the Midland Basin, Energen plans to further accelerate its exploratory and development Wolfcamp/Cline programs in the Permian Basin by adding 23 gross (23 net) wells to its 2014 drilling plans. These new wells are the major drivers of approximately $250 million of additional capital investment, bringing total drilling and development capital in 2014 to approximately $1.3 billion. (Prior guidance was $1.05 billion.)
Energen estimates that its 2014 production midpoint will be higher than prior guidance by approximately 0.5 million barrels of oil equivalent (MMBOE). This is a result of year-to-date production strength in Delaware Basin Wolfcamp wells and the expected production impact from wells coming on line more quickly than originally planned due to improved drilling efficiency. Energen’s new production guidance range is 24.9 - 25.9 MMBOE, with a midpoint of 25.4 MMBOE. (Prior guidance was a range of 24.4 – 25.4 MMBOE, with a midpoint of 24.9 MMBOE.)
The current-year acceleration is expected to have a greater impact on 2015 production. A preliminary look at 2015 production suggests that oil and natural gas liquids (NGL) growth could exceed 25 percent assuming a level of investment comparable to the new 2014 capital estimate. Total Permian Basin growth from 2014 to 2015 could exceed 30 percent.
First Quarter 2014 Earnings
For the 3 months ended March 31, 2014, Energen reported consolidated net income of $53.3 million, or $0.73 per diluted share. After adjusting for non-cash items and exploration and production (E&P) discontinued operations, Energen’s adjusted income from continuing operations (including utility operations) in the first quarter of 2014 totaled $77.0 million, or $1.05 per diluted share. This compares with adjusted income from continuing operations in the first quarter of 2013 of $80.7 million, or $1.12 per diluted share.
NOTE: The earnings of Energen’s utility subsidiary, Alabama Gas Corporation, are expected to be reflected in discontinued operations beginning with the quarter and year-to-date results for the period ending June 30, 2014.
Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
[See “Non-GAAP Financial Measures” beginning on pp. 12 for more information]
| 1Q14 | 1Q13 | ||||||||||||||||||
|
$M |
$/dil. sh. | $M | $/dil. sh. | ||||||||||||||||
| Net Income All Operations (GAAP) | $ | 53,316 | $ | 0.73 | $ | 56,692 | $ | 0.78 | |||||||||||
| Less: Non-cash Mark-to-Market gain/(loss) | (21,536 | ) | (0.29 | ) | (25,959 | ) | 0.36 | ||||||||||||
| Adjusted Net Income All Operations (Non-GAAP) | $ | 74,852 | $ | 1.02 | $ | 82,651 | $ | 1.14 | |||||||||||
| Less: E&P Discontinued Operations | |||||||||||||||||||
| Gain (Loss) on Disposal | (1,050 | ) | (0.01 | ) | -- | -- | |||||||||||||
| Income (Loss) from Discontinued Operations | (1,126 | ) | (0.02 | ) | 1,998 | 0.03 | |||||||||||||
| Adj. Income Continuing Operations (Non-GAAP) | $ | 77,028 | $ | 1.05 | $ | 80,653 | $ | 1.12 | |||||||||||
|
Note: Per share amounts may not sum due to rounding |
|||||||||||||||||||
The year-over-year decrease in adjusted income from continuing operations in the first quarter largely is the result of recent changes to Alabama Gas Corporation’s rate-setting mechanism, including a reduction in the utility’s allowed range of return on equity, partially offset by higher average equity. Alagasco’s net income for the three months ended March 31, 2014, totaled $43.0 million and compared with earnings of $47.2 million in the same period last year.
Energen’s oil and gas company, Energen Resources Corporation, generated adjusted income from continuing operations in the first quarter of 2014 that totaled $33.7 million and compared with $32.7 million in the same period last year. The benefits of a 23 percent increase in oil and NGL production and higher realized oil and natural gas prices were partially offset by higher DD&A expense, increased exploration expense largely associated with delay rentals, and higher price-driven production taxes.
Relative to the company’s internal expectations, first quarter 2014 adjusted income from continuing operations fell short at both subsidiaries. Revenue reductions under Alagasco’s Rate RSE were greater-than-anticipated largely due to weather-related increases in sales and recent changes to the rate-setting method. In addition, the net benefits of greater-than-expected production were more than offset by the timing of delay rental expenses, higher lease operating expense (LOE), and a lower-than-expected realized oil price due to above-budget WTS Midland and WTI Midland to WTI Cushing differentials.
Energen’s adjusted EBITDAX from continuing operations totaled $290 million in the first quarter of 2014, up approximately 14 percent from $254 million in the same period last year. Energen Resources had adjusted EBITDAX from continuing operations of $207 million in the first quarter of 2014, up approximately 27 percent from $163 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp.12 for more information and reconciliation.]
Production by Commodity (MBOE)
| Commodity | 1Q14 | 1Q13 | Change | |||||||||
| Continuing Operations | ||||||||||||
| Oil | 2,751 | 2,314 | 19 % | |||||||||
| NGL | 903 | 656 | 38 % | |||||||||
| Natural Gas | 2,354 | 2,303 | 2 % | |||||||||
| Total Continuing Operations | 6,008 | 5,273 | 14 % | |||||||||
| Discontinued Operations | 154 | 648 | ||||||||||
| Total All Operations | 6,162 | 5,921 | ||||||||||
Production from Continuing Operations by Area (MBOE)
| Area | 1Q14 | 1Q13 | Change | |||||||||
| Midland Basin | 1,537 | 985 | 56 % | |||||||||
| Wolfberry | 1,474 | 984 | ||||||||||
| Wolfcamp | 63 | 1 | ||||||||||
| Delaware Basin | 1,404 | 953 | 47 % | |||||||||
| 3rd Bone Spring/Other | 1,183 | 930 | ||||||||||
| Wolfcamp | 221 | 23 | ||||||||||
| Central Basin Platform | 1,016 | 1,086 | (6) % | |||||||||
| Total Permian Basin | 3,957 | 3,024 | 31 % | |||||||||
| San Juan Basin/Other | 2,051 | 2,249 | (9) % | |||||||||
| Total Continuing Operations | 6,008 | 5,273 | 14 % | |||||||||
Average Realized Sales Prices from Continuing Operations
| Commodity | 1Q14 | 1Q13 | Change | |||||||||||
| Oil (per barrel) | $ | 86.86 | $ | 85.65 | 1 % | |||||||||
| NGL (per gallon) | $ | 0.75 | $ | 0.77 | (2) % | |||||||||
| Natural Gas (per Mcf) | $ | 4.51 | $ | 4.17 | 8 % | |||||||||
In the first quarter of 2014, base LOE and marketing and transportation expenses decreased approximately 12 percent from the same period a year ago to $12.49 per BOE, while commodity price-driven production taxes increased approximately 26 percent on a per-unit basis to $3.29 per BOE. Together, total per-unit LOE in the first quarter of 2014 was $15.77, down approximately 6.5 percent from $16.86 in the same period last year.
Per-unit DD&A expense from continuing operations in the 1st quarter of 2014 totaled $20.52 per BOE, increasing approximately 15 percent from the same period last year largely due to year-over-year increases in development costs and greater oil volumes as a percent of total production.
Per-unit net G&A expense of $4.98 was approximately 1 percent higher than in the same period a year ago.
Wolfcamp Shale Exploration Results
(Locator map available at www.energen.com)
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 |
|||||||||||||||||||||||||||
|
San Saba |
A/
Glasscock |
7,300’ | 6,783’ | 27 | 921 | 719 | 113 | 533 | 876 | 653 | 125 | 588 | ||||||||||||||||||||||||
|
Jones |
A/
Martin |
7,500’ | 6,675’ | 27 | 1,171 | 842 | 190 | 836 | 843 | 630 | 123 | 542 | ||||||||||||||||||||||||
|
* Represents distance from vertical departure to toe |
||||||||||||||||||||||||||||||||||||
Energen’s first Wolfcamp exploratory well in its 2014 program tested the Wolfcamp A in Martin County. The Jones Holton #101H generated a peak 24-hour IP (3-stream) of 1,171 boepd (72% oil, 16% NGL, and 12% natural gas). With a completed length of 6,675 feet, the Jones Holton #101H tested at a peak 30-day average rate of 843 boepd (75% oil, 14% NGL, and 11% gas). These are the best IP and 30-day average rates known to have been reported for a Martin County Wolfcamp A well. Another Wolfcamp A well in Martin County is awaiting completion, as is the company’s first test of the Wolfcamp A in Howard County.
In southern Glasscock County, the San Saba NS 37-48 #106H tested the Wolfcamp A and demonstrated the continued consistency and predictability of the A bench wells in this area. One of the last two wells in Energen’s 2013 drilling program, it generated a 24-hour peak IP of 921 boepd (78% oil, 12% NGL, and 10% gas). The peak 30-day average rate was 876 boepd (75% oil, 14% NGL, and 11% gas).
The last well in Energen’s 2013 exploratory drilling program in the Midland Basin is awaiting completion, and four wells in the 2014 exploratory program currently are awaiting completion or preparing to test. Energen’s 57-well Wolfcamp development program in southern Glasscock County is focused on drilling stacked laterals in the “A” and “B” benches with lateral lengths of 6,700 feet and 7,500 feet.
DELAWARE BASIN
| Well |
Zone/
County |
Lateral length |
Frac |
Peak 24-Hour IP | Peak 20-day Average | |||||||||||||||||||||||||||||||
| Drilled* | Completed | Boepd |
Oil |
NGL |
Gas |
Boepd |
Oil |
NGL |
Gas |
|||||||||||||||||||||||||||
|
Langley |
B/
Reeves |
4,830’ | 4,237’ | 18 | 2,009 | 1,018 | 467 | 3,146 | 1,813 | 870 | 444 | 2,994 | ||||||||||||||||||||||||
|
* Represents distance from vertical departure to toe |
||||||||||||||||||||||||||||||||||||
| Well |
Zone/
County |
Lateral length |
Frac |
Peak 24-Hour IP | Peak 30-day Average | |||||||||||||||||||||||||||||||
| Drilled* | Completed | Boepd |
Oil |
NGL |
Gas |
Boepd |
Oil |
NGL |
Gas |
|||||||||||||||||||||||||||
|
Matador |
A/ |
4,800’ | 4,282’ | 19 | 1,338 | 968 | 190 | 1,080 | 1,057 | 745 | 160 | 910 | ||||||||||||||||||||||||
|
* Represents distance from vertical departure to toe |
||||||||||||||||||||||||||||||||||||
Energen tested two more excellent Wolfcamp wells in Reeves County in the southern Delaware Basin. The Langley 2-36 #1H tested the “B” bench at a peak 24-hour IP (3-stream) of 2,009 boepd (51% oil, 23% NGL, and 26% gas). This is Energen’s fourth Reeves County Wolfcamp well to top 2,000 boepd. The Langley’s peak 20-day average rate (3-stream) was 1,813 boepd (48% oil, 24% NGL, and 28% gas).
Located south of the previously disclosed Bodacious C7-19 #1H and Red Rock 6-6 #1H in the “A” bench of the Wolfcamp shale, the Matador 6-33 #1H tested at a peak 24-hour IP rate of 1,338 boepd. The 3-stream rate was 72% oil, 14% NGL, and 14% gas. The peak 30-day average rate (3-stream) was 1,057 boepd (71% oil, 15% NGL, and 14% gas).
The first four wells in the company’s 2014 exploratory drilling program in the Delaware Basin currently are drilling or completing.
2014 Capital and Production Guidance
Energen has enhanced its drilling efficiency in the Midland Basin in 2014. The company has decreased drill cycle times for its four horizontal Wolfcamp development rigs through improved planning, accelerated permitting, accelerated location and water handling facilities construction, the use of spudder rigs to set intermediate pipe, and increased overall drilling efficiency. The results have been to lower drill cycle times for the horizontal development rigs by 7 days from an original target of 28 days to a current 21-day cycle from rig-up to rig-up. This allows for an increased number of wells to be drilled at a lower cost per well.
Given these efficiency gains as well as better-than-expected first quarter production from Delaware Basin Wolfcamp wells, Energen plans to increase its capital investment in 2014 by $250 million and drill 23 gross (23 net) additional Wolfcamp/Cline wells. This brings planned capital for drilling and development in 2014 to approximately $1.3 billion.
The new operated wells include 17 development wells in southern Glasscock County; 3 exploratory Wolfcamp wells in the Midland Basin; a Cline well in the Midland Basin; and 2 Delaware Basin Wolfcamp wells.
Other adjustments to capital include decreased drill and complete costs for Wolfcamp development wells in southern Glasscock County, increased drill and complete costs for Wolfcamp exploratory wells in the Delaware Basin primarily due to higher costs for infrastructure, facilities, and testing; 2 gross (1 net) additional non-operated Niobrara wells in the San Juan Basin; increased facilities; and increased working interests.
2014e Drilling and Development Capital
|
Capital ($MM) |
Operated Wells To Be Drilled Gross (Net) |
|||||||||||||||||||
|
Revised |
Original |
Revised |
Original |
|||||||||||||||||
| Midland Basin | $ | 840 | $ | 668 |
134 |
(124 |
) |
113 |
(106 |
) |
||||||||||
|
Wolfcamp/Cline |
650 | 475 |
80 |
(76 |
) |
59 |
(57 |
) |
||||||||||||
|
Wolfberry/Other |
120 | 121 |
54 |
(48 |
) |
54 |
(49 |
) |
||||||||||||
|
Facilities/Other |
70 | 72 | ||||||||||||||||||
|
Delaware Basin |
$ | 380 | $ | 315 |
41 |
(38 |
) |
41 |
(34 |
) |
||||||||||
|
3(rd) Bone Spring/Other |
185 | 173 |
27 |
(25 |
) |
29 |
(24 |
) |
||||||||||||
|
Wolfcamp |
160 | 108 |
14 |
(13 |
) |
12 |
(10 |
) |
||||||||||||
|
Facilities/Other |
35 | 34 | ||||||||||||||||||
| Other Permian | $ | 42 | $ | 42 |
26 |
(22 |
)* |
26 |
(21 |
)* |
||||||||||
|
Waterfloods/CO(2) floods |
17 | 17 |
26 |
(22 |
)* |
26 |
(21 |
)* |
||||||||||||
|
Facilities/Other |
25 | 25 | ||||||||||||||||||
|
San Juan Basin/Other |
$ | 23 | $ | 15 |
0 |
(0 |
) |
0 |
(0 |
) |
||||||||||
|
Facilities/Other |
23 | 15 | ||||||||||||||||||
| Net Carry In/Carry Out | $ | 15 | $ | 10 | ||||||||||||||||
|
TOTAL – Contg. Ops |
$ |
1,300 |
$ |
1,050 |
201 |
(184 |
) |
180 |
(161 |
) |
||||||||||
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
Production from continuing operations in 2014 is estimated to increase 0.5 MMBOE to a midpoint of 25.4 MMBOE within a range of 24.9-25.9 MMBOE.
Production from Continuing Operations by Area (MMBOE)
| Area | 2014e Midpoint | 2013 | |||||||
| Revised | Original | ||||||||
| Midland Basin | 7.7 | 7.4 | 5.1 | ||||||
| Wolfcamp/Cline | 2.8 | 2.2 | 0.0 | ||||||
| Wolfberry | 4.9 | 5.2 | 5.1 | ||||||
| Delaware Basin | 5.6 | 5.4 | 4.7 | ||||||
| 3rd Bone Spring/Other | 4.5 | 4.5 | 4.2 | ||||||
| Wolfcamp | 1.1 | 0.9 | 0.5 | ||||||
| Central Basin Platform | 3.8 | 3.7 | 4.4 | ||||||
| Total Permian Basin | 17.1 | 16.5 | 14.2 | ||||||
| San Juan Basin/Other | 8.3 | 8.4 | 9.1 | ||||||
| Total Continuing Operations | 25.4 | 24.9 | 23.3 | ||||||
Production from Continuing Operations by Product (MMBOE)
| Commodity | 2014e Midpoint | 2013 |
2013 vs Revised |
|||||||||
| Revised | Original | |||||||||||
| Oil | 11.8 | 11.4 | 10.4 | 13 % | ||||||||
| NGL | 3.9 | 3.8 | 3.2 | 22 % | ||||||||
| Natural Gas | 9.7 | 9.7 | 9.7 | -- | ||||||||
| Total Continuing Operations | 25.4 | 24.9 | 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 | 4.9 | 3.2 | 1.5 | 1.0 | 1.3 | 0.9 | 7.7 | 5.1 | ||||||||||||||||
| Delaware Basin | 3.4 | 3.1 | 1.0 | 0.7 | 1.2 | 0.9 | 5.6 | 4.7 | ||||||||||||||||
| Central Basin Platform/Other | 3.4 | 3.9 | 0.2 | 0.2 | 0.2 | 0.2 | 3.8 | 4.4 | ||||||||||||||||
| San Juan Basin/Other | 0.1 | 0.1 | 1.2 | 1.3 | 7.0 | 7.7 | 8.3 | 9.1 | ||||||||||||||||
| Total Continuing Operations | 11.8 | 10.4 | 3.9 | 3.2 | 9.7 | 9.7 | 25.4 | 23.3 | ||||||||||||||||
|
NOTE: 2014e production reflects the midpoint of guidance |
||||||||||||||||||||||||
Production from Continuing Operations by Basin per Quarter (MMBOE)
| Basin | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | ||||||||||||||||||||
| 2014 | 2013 | 2014e | 2013 | 2014e | 2013 | 2014e | 2013 | |||||||||||||||||
| Midland Basin | 1.5 | 1.0 | 1.6 | 1.2 | 2.1 | 1.4 | 2.5 | 1.5 | ||||||||||||||||
| Delaware Basin | 1.4 | 1.0 | 1.3 | 1.2 | 1.4 | 1.3 | 1.5 | 1.2 | ||||||||||||||||
| Central Basin Platform/Other | 1.0 | 1.1 | 1.0 | 1.1 | 0.9 | 1.1 | 0.9 | 1.1 | ||||||||||||||||
| San Juan Basin/Other | 2.1 | 2.2 | 2.1 | 2.4 | 2.1 | 2.3 | 2.0 | 2.2 | ||||||||||||||||
| Total Production – Contg Ops | 6.0 | 5.3 | 6.0 | 5.9 | 6.5 | 6.1 | 6.9 | 6.0 | ||||||||||||||||
|
NOTE: 2014e production reflects the midpoint of guidance |
||||||||||||||||||||||||
2014 Financial Guidance
Energen is revising its 2014 guidance for after-tax cash flows and earnings to reflect numerous adjustments including year-to-date results, increased production estimate, additional commodity and basis hedges, revised price assumptions for unhedged production and basis differentials, and reduced interest expense. Importantly, Energen’s revised 2014 guidance reflects only its oil and gas exploration and production business.
The sale of Alagasco, announced in early April, is expected to close in 2014. Energen’s financial statements beginning with the three and six months ended June 30, 2014, are expected to reflect utility results as discontinued operations. The final classification of certain line item amounts between Alagasco and Energen cannot be determined prior to close and could cause variability between guidance and actual continuing operations for 2014.
Energen’s pro forma 2014 guidance range for after-tax cash flows (non-GAAP) is an estimated $848 million to $878 million; in addition, Energen estimates that it will receive after-tax proceeds of approximately $1.1 billion from the sale of its utility. Pro forma 2014 earnings are estimated to range from $157 million to $187 million, or $2.15-$2.55 per diluted share.
Energen’s estimated expenses from continuing operations in 2014 on a per-BOE basis are:
| Lease Operating Expense | ||||||||
| Base, marketing, and transportation | $ | 11.35- $11.80 | ||||||
| Production taxes | $ | 3.00- $3.20 | ||||||
| DD&A expense | $ | 20.50- $21.50 | ||||||
| General & Administrative expense, net | $ | 4.70- $5.10 | ||||||
| Interest expense | $ | 2.15- $2.35 | ||||||
| Exploration expense (delay rentals, seismic, G&G) | $ | 0.85- $0.95 | ||||||
Approximately 77 percent of the company’s total estimated midpoint of production from continuing operations for the remainder of 2014 is hedged, including the recent addition of some NGL contracts. 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. They are $4.40 per barrel (sour oil) and $4.20 per barrel (WTI Midland to WTI Cushing). Energen estimates that approximately 73 percent of its oil production for the remainder of 2014 will be sweet. Gas basis assumptions are $0.09 per Mcf in the Permian Basin and $0.12 per Mcf in the San Juan Basin.
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 |
7.4 |
MMBO |
9.0 |
MMBO |
82 % |
$ 92.65 per barrel |
|||||||
|
NGL |
46.0 |
MMgal |
126.8 |
MMgal |
36 % |
$ 0.93 per gallon |
|||||||
|
Natural Gas |
38.8 |
Bcf |
43.9 |
Bcf |
88 % |
$ 4.54 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 $2.70 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 $870,000; every 1-cent change in the average price of NGL from $0.92 per gallon is estimated to be approximately $400,000; and every 10-cent change in the average NYMEX price of gas from $4.50 represents an immaterial impact. Price-related events such as substantial basis differential changes could cause these sensitivities to be different from those outlined.
2015 HEDGES
The company has been adding to its 2015 hedge position in recent weeks. The following table summarizes Energen’s current hedge position for 2015:
|
Commodity |
Hedge Volumes |
NYMEXe Price |
|||||||
|
Oil |
8.3 |
MMBO |
$ |
89.30 |
per barrel |
||||
|
Natural Gas |
29.0 |
Bcf |
$ |
4.30 |
per Mcf |
||||
Basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price in the table above by adding to them Energen Resources' assumed San Juan and Permian basis differentials for 2015 of $0.14 per Mcf and $0.20 per Mcf, respectively.
CONFERENCE CALL
Energen will hold its quarterly conference call Thursday, May 1, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-866-939-3921. 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 a loss 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 3/31/2014 | |||||||||
| Consolidated Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
|||||||
| Net Income (GAAP) | 53.3 | 0.73 | |||||||
| Non-cash mark-to-market losses (net of $12.1 tax) | 21.5 | 0.29 | |||||||
| Adjusted Net Income from All Operations (Non-GAAP) | 74.9 | 1.02 | |||||||
| Loss on disposal of discontinued operations (net of $0.6 tax) | 1.1 | 0.01 | |||||||
| Loss from discontinued operations (net of $1.0 tax) | 1.1 | 0.02 | |||||||
| Adjusted Income from Continuing Operations (Non-GAAP) | 77.0 | 1.05 | |||||||
| Quarter Ended 3/31/2013 | |||||||||
| Consolidated Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
|||||||
| Net Income (GAAP) | 56.7 | 0.78 | |||||||
| Non-cash mark-to-market losses (net of $15.1 tax) | 26.0 | 0.36 | |||||||
| Adjusted Net Income from All Operations (Non-GAAP) | 82.7 | 1.14 | |||||||
| Income from discontinued operations (net of $1.2 tax) | (2.0 | ) | (0.03 | ) | |||||
| Adjusted Income from Continuing Operations (Non-GAAP) | 80.7 | 1.12 | |||||||
| Note: Amounts may not sum due to rounding | |||||||||
|
Non-GAAP Financial Measures
Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes certain non-cash mark-to-market derivative financial instruments. Adjusted income from continuing operations further excludes a loss on disposal of discontinued operations and a loss from discontinued operations. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies. |
||||
| Energen Resources Net Income ($ in millions) | Quarter Ended 3/31/2014 | |||
| Net Income (GAAP) | 10.0 | |||
| Non-cash mark-to-market losses (net of $15.1 tax) | 21.5 | |||
| Adjusted Net Income from All Operations (Non-GAAP) | 31.5 | |||
| Loss on disposal of discontinued operations (net of $0.6 tax) | 1.1 | |||
| Loss from discontinued operations (net of $1.0 tax) | 1.1 | |||
| Adjusted Income from Continuing Operations (Non-GAAP) | 33.7 | |||
| Energen Resources Net Income ($ in millions) | Quarter Ended 3/31/2013 | |||
| Net Income (GAAP) | 8.8 | |||
| Non-cash mark-to-market losses (net of $15.1 tax) | 26.0 | |||
| Adjusted Net Income from All Operations (Non-GAAP) | 34.8 | |||
| Income from discontinued operations (net of $1.2 tax) | (2.0 | ) | ||
| Adjusted Income from Continuing Operations (Non-GAAP) | 32.7 | |||
| Note: Amounts may not sum due to rounding | ||||
|
Non-GAAP Financial Measures
Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDAX from continuing operations further excludes a loss on disposal of discontinued operations, certain non-cash mark-to-market derivative financial instruments and a loss from discontinued operations. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies. |
|||||||
| Reconciliation To GAAP Information | Year-to-Date Ended 3/31 | ||||||
| ($ in millions) | 2013 | 2014 | |||||
| Consolidated Net Income (GAAP) | 56.7 | 53.3 | |||||
| Interest expense | 16.8 | 17.6 | |||||
| Income tax expense | 32.4 | 32.8 | |||||
| Depreciation, depletion and amortization | 105.8 | 135.7 | |||||
| Accretion expense | 1.7 | 1.8 | |||||
| Exploration expense | 1.5 | 12.8 | |||||
| Adjustment for loss on disposal of discontinued operations, net of tax | - | 1.1 | |||||
| Adjustment for mark-to-market losses | 41.0 | 33.7 | |||||
| Adjustment for (income) loss from discontinued operations, net of tax | (2.0 | ) | 1.1 | ||||
| Consolidated Adjusted EBITDAX from Continuing Operations (Non-GAAP) | 253.9 | 290.0 | |||||
| Reconciliation To GAAP Information | Year-to-Date Ended 3/31 | ||||||
| ($ in millions) | 2013 | 2014 | |||||
| Energen Resources Net Income (GAAP) | 8.8 | 10.0 | |||||
| Interest expense | 12.8 | 14.1 | |||||
| Income tax expense | 4.4 | 7.6 | |||||
| Depreciation, depletion and amortization | 95.1 | 124.4 | |||||
| Accretion expense | 1.7 | 1.8 | |||||
| Exploration expense | 1.5 | 12.8 | |||||
| Adjustment for loss on disposal of discontinued operations, net of tax | - | 1.1 | |||||
| Adjustment for mark-to-market losses | 41.0 | 33.7 | |||||
| Adjustment for (income) loss from discontinued operations, net of tax | (2.0 | ) | 1.1 | ||||
| Energen Resources Adjusted EBITDAX from Continuing Operations (Non-GAAP) | 163.3 | 206.5 | |||||
| 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 | 157 | 187 | ||||||||||||
| Alabama Gas Corporation (GAAP)* | 49 | 57 | - | - | ||||||||||||
| Consolidated Net Income (GAAP)* | 254 | 205 | 157 | 187 | ||||||||||||
| Depreciation, depletion and amortization | 441 | 558 | 541 | 541 | ||||||||||||
| Deferred income taxes | 124 | 84 | 101 | 101 | ||||||||||||
| Exploratory expense | 17 | 16 | - | - | ||||||||||||
| Other | (34 | ) | 48 | 49 | 49 | |||||||||||
| After-tax Cash Flows (Non-GAAP) | 802 | 911 | 848 | 878 | ||||||||||||
| Changes in assets and liabilities and other adjustments | (66 | ) | 16 | (25 | ) | (25 | ) | |||||||||
| Net Cash Provided by Operating Activities (GAAP) | 736 | 927 | 823 | 853 | ||||||||||||
| 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 | 823 | 853 | ||||||||||||
| Changes in assets and liabilities and other adjustments | 66 | (16 | ) | 25 | 25 | |||||||||||
| After-tax Cash Flow (Non-GAAP) | 802 | 911 | 848 | 878 | ||||||||||||
| Less: AGC cash flows from operations and other* | (103 | ) | (116 | ) | - | - | ||||||||||
| Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP) | 699 | 795 | 848 | 878 | ||||||||||||
|
* 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. |
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|
(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. |
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|
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 3 months ending March 31, 2014 and 2013 |
|||||||||||||||
| 1st Quarter | |||||||||||||||
| (in thousands, except per share data) | 2014 | 2013 | Change | ||||||||||||
| Operating Revenues | |||||||||||||||
| Oil and gas operations | $ | 297,278 | $ | 236,331 | $ | 60,947 | |||||||||
| Natural gas distribution | 263,900 | 237,685 | 26,215 | ||||||||||||
| Total operating revenues | 561,178 | 474,016 | 87,162 | ||||||||||||
| Operating Expenses | |||||||||||||||
| Cost of gas | 128,114 | 95,442 | 32,672 | ||||||||||||
| Operations and maintenance | 155,072 | 140,712 | 14,360 | ||||||||||||
| Depreciation, depletion and amortization | 135,697 | 105,828 | 29,869 | ||||||||||||
| Taxes, other than income taxes | 35,853 | 28,157 | 7,696 | ||||||||||||
| Accretion expense | 1,843 | 1,687 | 156 | ||||||||||||
| Total operating expenses | 456,579 | 371,826 | 84,753 | ||||||||||||
| Operating Income | 104,599 | 102,190 | 2,409 | ||||||||||||
| Other Income (Expense) | |||||||||||||||
| Interest expense | (17,640 | ) | (16,752 | ) | (888 | ) | |||||||||
| Other income | 1,384 | 1,734 | (350 | ) | |||||||||||
| Other expense | (54 | ) | (69 | ) | 15 | ||||||||||
| Total other expense | (16,310 | ) | (15,087 | ) | (1,223 | ) | |||||||||
| Income From Continuing Operations Before Income Taxes |
88,289 |
87,103 |
1,186 |
||||||||||||
| Income tax expense | 32,797 | 32,409 | 388 | ||||||||||||
| Income From Continuing Operations | 55,492 | 54,694 | 798 | ||||||||||||
| Discontinued Operations, net of taxes | |||||||||||||||
| Income (loss) from discontinued operations | (1,126 | ) | 1,998 | (3,124 | ) | ||||||||||
| Loss on disposal of discontinued operations | (1,050 | ) | − | (1,050 | ) | ||||||||||
| Income (Loss) From Discontinued Operations | (2,176 | ) | 1,998 | (4,174 | ) | ||||||||||
| Net Income | $ | 53,316 | $ | 56,692 | $ | (3,376 | ) | ||||||||
| Diluted Earnings Per Average Common Share | |||||||||||||||
| Continuing operations | $ | 0.76 | $ | 0.75 | $ | 0.01 | |||||||||
| Discontinued operations | (0.03 | ) | 0.03 | (0.06 | ) | ||||||||||
| Net Income | $ | 0.73 | $ | 0.78 | $ | (0.05 | ) | ||||||||
| Basic Earnings Per Average Common Share | |||||||||||||||
| Continuing operations | $ | 0.76 | $ | 0.76 | $ | − | |||||||||
| Discontinued operations | (0.03 | ) | 0.03 | (0.06 | ) | ||||||||||
| Net Income | $ | 0.73 | $ | 0.79 | $ | (0.06 | ) | ||||||||
| Diluted Avg. Common Shares Outstanding | 73,043 | 72,288 | 755 | ||||||||||||
| Basic Avg. Common Shares Outstanding | 72,628 | 72,143 | 485 | ||||||||||||
| Dividends Per Common Share | $ | 0.15 | $ | 0.145 | $ | 0.005 | |||||||||
|
CONSOLIDATED BALANCE SHEETS (UNAUDITED) |
||||||||
| (in thousands) | March 31, 2014 | December 31, 2013 | ||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and cash equivalents | $ | 35,343 | $ | 5,555 | ||||
| Accounts receivable, net of allowance | 299,118 | 257,545 | ||||||
| Inventories | 36,896 | 52,330 | ||||||
| Regulatory asset | 1,283 | 2,756 | ||||||
| Assets held for sale | 1,871 | 51,104 | ||||||
| Other | 64,518 | 57,941 | ||||||
| Total current assets | 439,029 | 427,231 | ||||||
| Property, Plant and Equipment | ||||||||
| Oil and gas properties, net | 5,231,851 | 5,087,573 | ||||||
| Utility plant, net | 888,177 | 885,509 | ||||||
| Other property, net | 33,690 | 30,556 | ||||||
| Total property, plant and equipment, net | 6,153,718 | 6,003,638 | ||||||
| Other Assets | ||||||||
| Regulatory asset | 82,570 | 84,890 | ||||||
| Long-term derivative instruments | 2,638 | 5,439 | ||||||
| Other | 102,435 | 101,014 | ||||||
| Total other assets | 187,643 | 191,343 | ||||||
| TOTAL ASSETS | $ | 6,780,390 | $ | 6,622,212 | ||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
| Current Liabilities | ||||||||
| Long-term debt due within one year | $ | 60,000 | $ | 60,000 | ||||
| Notes payable to banks | 575,000 | 539,000 | ||||||
| Accounts payable | 300,069 | 250,756 | ||||||
| Regulatory liability | 80,698 | 49,006 | ||||||
| Other | 194,717 | 211,131 | ||||||
| Total current liabilities | 1,210,484 | 1,109,893 | ||||||
| Long-term debt | 1,328,442 | 1,343,464 | ||||||
| Deferred Credits and Other Liabilities | ||||||||
| Regulatory liability | 83,240 | 94,125 | ||||||
| Deferred income taxes | 1,037,898 | 1,013,245 | ||||||
| Long-term derivative instruments | 1,011 | 398 | ||||||
| Other | 208,188 | 203,068 | ||||||
| Total deferred credits and other liabilities | 1,330,337 | 1,310,836 | ||||||
| Total Shareholders’ Equity | 2,911,127 | 2,858,019 | ||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 6,780,390 | $ | 6,622,212 | ||||
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending March 31, 2014 and 2013 |
|||||||||||||||
| 1st Quarter | |||||||||||||||
| (in thousands, except sales price data) | 2014 | 2013 | Change | ||||||||||||
| Oil and Gas Operations (GAAP) | |||||||||||||||
| Operating revenues from continuing operations | |||||||||||||||
| Natural gas | $ | 51,252 | $ | 53,216 | $ | (1,964 | ) | ||||||||
| Oil | 217,493 | 161,551 | 55,942 | ||||||||||||
| Natural gas liquids | 28,686 | 21,116 | 7,570 | ||||||||||||
| Other | (153 | ) | 448 | (601 | ) | ||||||||||
| Total (GAAP) | $ | 297,278 | $ | 236,331 | $ | 60,947 | |||||||||
|
Oil and Gas Operations excluding mark-to-market (Non-GAAP) |
|||||||||||||||
| Operating revenues from continuing operations | |||||||||||||||
| Natural gas | $ | 63,756 | $ | 57,591 | $ | 6,165 | |||||||||
| Oil | 238,957 | 198,203 | 40,754 | ||||||||||||
| Natural gas liquids | 28,399 | 21,137 | 7,262 | ||||||||||||
| Other | (153 | ) | 448 | (601 | ) | ||||||||||
| Total (Non-GAAP)* | $ | 330,959 | $ | 277,379 | $ | 53,580 | |||||||||
| Production volumes from continuing operations | |||||||||||||||
| Natural gas (MMcf) | 14,124 | 13,818 | 306 | ||||||||||||
| Oil (MBbl) | 2,751 | 2,314 | 437 | ||||||||||||
| Natural gas liquids (MMgal) | 37.9 | 27.6 | 10.3 | ||||||||||||
| Production volumes from continuing operations (MBOE) |
6,008 |
5,273 |
735 |
||||||||||||
| Total production volumes (MBOE) | 6,162 | 5,921 | 241 | ||||||||||||
| Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments | |||||||||||||||
| Natural gas (Mcf) | $ | 4.51 | $ | 4.17 | $ | 0.34 | |||||||||
| Oil (barrel) | $ | 86.86 | $ | 85.65 | $ | 1.21 | |||||||||
| Natural gas liquids (gallon) | $ | 0.75 | $ | 0.77 | $ | (0.02 | ) | ||||||||
|
Revenue per unit of production excluding effects of all derivative instruments |
|||||||||||||||
| Natural gas (Mcf) | $ | 4.88 | $ | 3.29 | $ | 1.59 | |||||||||
| Oil (barrel) | $ | 92.24 | $ | 82.44 | $ | 9.80 | |||||||||
| Natural gas liquids (gallon) | $ | 0.74 | $ | 0.68 | $ | 0.06 | |||||||||
| Other data from continuing operations | |||||||||||||||
| Lease operating expense (LOE) | |||||||||||||||
| LOE and other | $ | 75,012 | $ | 75,155 | $ | (143 | ) | ||||||||
| Production taxes | 19,756 | 13,763 | 5,993 | ||||||||||||
| Total | $ | 94,768 | $ | 88,918 | $ | 5,850 | |||||||||
| Depreciation, depletion and amortization | $ | 124,372 | $ | 95,099 | $ | 29,273 | |||||||||
| General and administrative expense | $ | 29,933 | $ | 25,948 | $ | 3,985 | |||||||||
| Capital expenditures | $ | 271,696 | $ | 285,053 | $ | (13,357 | ) | ||||||||
| Exploration expenditures | $ | 12,814 | $ | 1,498 | $ | 11,316 | |||||||||
| Operating income | $ | 33,548 | $ | 23,181 | $ | 10,367 | |||||||||
| *Operating revenues excluding mark-to-market losses of $33,681 and $41,048 in first quarter 2014 and 2013, respectively. | |||||||||||||||
| Natural Gas Distribution | |||||||||||||||
| Operating revenues | |||||||||||||||
| Residential | $ | 191,611 | $ | 162,739 | $ | 28,872 | |||||||||
| Commercial and industrial | 68,992 | 57,599 | 11,393 | ||||||||||||
| Transportation | 18,034 | 18,240 | (206 | ) | |||||||||||
| Other | (14,737 | ) | (893 | ) | (13,844 | ) | |||||||||
| Total | $ | 263,900 | $ | 237,685 | $ | 26,215 | |||||||||
| Gas delivery volumes (MMcf) | |||||||||||||||
| Residential | 13,053 | 10,382 | 2,671 | ||||||||||||
| Commercial and industrial | 5,315 | 4,207 | 1,108 | ||||||||||||
| Transportation | 12,782 | 12,790 | (8 | ) | |||||||||||
| Total | 31,150 | 27,379 | 3,771 | ||||||||||||
| Other data | |||||||||||||||
| Depreciation and amortization | $ | 11,325 | $ | 10,729 | $ | 596 | |||||||||
| Capital expenditures | $ | 13,594 | $ | 19,697 | $ | (6,103 | ) | ||||||||
| Operating income | $ | 72,351 | $ | 79,293 | $ | (6,942 | ) | ||||||||